Methods and compositions relating to minimizing particulate migration over long intervals

ABSTRACT

Methods are included that are useful in treating subterranean formations and, more particularly, to minimizing particulate migration over long intervals in subterranean well bores that may be horizontal, vertical, deviated, or otherwise nonlinear. In one embodiment, a method is presented comprising: providing a well bore comprising an open hole section of about 30 feet or more that comprises an open hole section with a filter cake neighboring at least a portion of a reservoir; allowing the integrity of at least a portion of the filter cake to become compromised; and treating at least a portion of the open hole section with a consolidating agent system in a single stage operation so as to at least partially reduce particulate migration in the open hole section.

BACKGROUND

The present invention relates to methods, compositions, systems, anddevices useful in treating subterranean formations and, moreparticularly, to consolidating potentially relatively unconsolidatedportions of subterranean formations and minimizing the flowback ofunconsolidated particulate materials such as formation fines and sand(referred to collectively herein as “particulate migration”) over longintervals. More specifically, the present invention relates to methodsfor applying consolidating agent systems over at least a portion of along interval in a subterranean well bore that may be horizontal,vertical, deviated, or otherwise nonlinear.

A type of particulate migration that may affect fluid conductivity in asubterranean formation is the flowback of unconsolidated particulatematerials (e.g., formation fines, proppant particulates, etc.) throughthe conductive channels in the subterranean formation, which can, forexample, clog or impair the conductive channels and/or damage theinterior of the formation or equipment. Another issue that cannegatively impact conductivity and further complicate the effects ofparticulate migration is the tendency of mineral surfaces in asubterranean formation to undergo chemical reactions caused, at least inpart, by conditions created by mechanical stresses on those minerals(e.g., fracturing of mineral surfaces, compaction of mineralparticulates, etc.). These reactions are referred herein to as“stress-activated reactions” or “stress-activated reactivity.” The term“modifying the stress-activated reactivity of a mineral surface” and itsderivatives as used herein refers to increasing or decreasing thetendency of a mineral surface in a subterranean formation to undergo oneor more stress-activated reactions, or attaching a compound to themineral surface that is capable of participating in one or moresubsequent reactions with a second compound.

There are several techniques to control particulate migration and modifythe stress-activated reactivity of mineral surfaces in a formation, someof which may involve the use of consolidating agent systems. The term“consolidating agent” or “consolidating agent system” (the terms may beused interchangeably) as used herein includes any compound orcombination of compounds that is capable of reducing particulatemigration in a subterranean formation and/or modifying thestress-activated reactivity of subterranean surfaces in a subterraneanformation. Consolidating agent systems are thought to enhance or, insome instances, alter a subterranean formation's mechanical propertiesto prevent or reduce the potential for particulate migration andstress-activated reactivity, and perhaps providing relatively smallincreases in mechanical strength.

One method used to modify particulate migration parameters in somesubterranean formations involves consolidating unconsolidated portionsof subterranean formations into relatively stable permeable masses byapplying a consolidating agent system to an unconsolidated portion ofthe formation. One example of such a method is applying a curable resinto a portion of a subterranean zone, followed by a spacer fluid, andthen a catalyst that can activate the resin. Another example of suchmethods involves applying a tackifying composition (aqueous- ornon-aqueous-based) to a portion of the formation in an effort to reducethe migration of particulates therein. Whereas a curable resincomposition may produce relatively hard masses, the use of a tackifyingcomposition produces more malleable consolidated masses.

While previously known consolidating agent systems are thought to begenerally effective over short productive intervals (e.g., less thanabout 30 feet), effective placement of consolidation chemicals overheterogeneous long intervals has often proven time-consuming anddifficult. The term “long interval” as used herein refers to an openhole section of about 30 feet or more in a subterranean well borepenetrating a subterranean formation. For example, some long vertical ordeviated well intervals may be about 30 feet to about 100, 250, or 500feet, and some long horizontal intervals may be about 500 feet to about10,000 feet. Some may be longer.

Wells with longer production intervals are typically completed usingcased hole or open hole gravel pack techniques. Such gravel packtechniques may involve placing a sand control screen to providesecondary filtration and mechanical support and a layer of uniformlygraded gravel or sand between the formation and screen to act as aprimary filtration layer, thus preventing particulate migration. Theseconventional gravel pack completions require large bore completionsbecause of the need to install both screens and gravel, requiring longand complex pumping operations, which take additional rig time. Theplacement of the gravel in long horizontal intervals can also be complexif there are borehole quality or fluid loss problems. In many cases,alternate path technologies are used where additional space is requiredto attach shunt tubes on the outside of the screen to act as transporttubes to ensure complete gravel placement.

If a consolidating-agent-type of system is chosen, typical systems forplacing chemicals over a long production interval may involve selectiveinjection-type tools where a short section of the borehole is isolated,then treated with consolidating agents. The tools are then moved to thenext interval and the process is repeated until the entire reservoirsection has been treated. Such treatments may be referred to as multiplestage treatments. For long intervals, this process can be verytime-consuming and complex as each injection step will require multiplefluid stages. Further, it is necessary to keep very accurate track offluids in the tubulars through the entire treatment, which can betime-consuming and difficult. Such stepped treatments may take severaldays of rig time to complete. A single stage operation (i.e., one thatdoes not require such multiple fluid stages to place the consolidatingagent system over a long interval) could have fewer complications andtake less rig time.

Filter cake (e.g., the residue deposited on the walls of a well bore bya fluid, usually a slurry, such as a drilling fluid) may control fluidloss and minimize formation damage during drilling and completion.Typical filter cakes may comprise bridging agents and in some instances,polymeric components, depending on the composition of the fluid used toform the filter cake. In typical sand control completions, a filter cakemay stay intact until installation of a sand control completion.

While filter cakes may be beneficial, it is generally thought to bebeneficial to remove filter cakes from producing zones once the well isplaced into production. Generally, a filter cake is removed mechanicallyor chemically, or by allowing it to degrade with produced fluids. Onemethod for degrading filter cakes from producing formations involvesincluding an acid-soluble particulate bridging agent for bridging overthe formation pores in the drilling, fracturing, gravel transport, orother servicing fluid that forms the filter cake. Such an acid-solublefilter cake could then be degraded by placing a strong acid solution incontact with the filter cake and allowing that solution to remain incontact for a period of time sufficient to degrade the filter cake by atleast interacting with the acid-soluble bridging agents.

One consideration in degrading a deposited filter cake from asubterranean well bore formation often involves the timing of suchdegradation. For instance, in situations where sand control of theformation is a concern, a filter cake is thought to offer some degree ofcontrol over unconsolidated particulates in the subterranean formationwhile placing the gravel pack. For example, if the filter cake isremoved prior to gravel packing, the unconsolidated particulates maymigrate, and as a result, well bore stability problems may arise thatmay cause collapse of the well bore, thus preventing the installation ofa gravel pack. Additionally, loss of filter cake integrity can alsoresult in severe losses of fluid during completion operations or graveldisplacement, creating well control problems or the inability toeffectively place gravel across the entire interval. While installingthe screen and placing the gravel before degrading the filter cake mayhelp control unconsolidated particulates, prevent undesirable losses ofwell bore fluids, and maintain borehole stability, as a result thefilter cake itself may be more difficult to degrade. In such instances,the screen and gravel may represent a physical barrier between thefilter cake on walls of the well bore and the filter cake degradationfluid used to degrade the filter cake.

An additional problem that may affect long production intervals thatoften needs to be managed is the presence of shale. Shale can beproblematic because it can generate a large volume of fines. Oftentimes,it may be desirable to physically isolate portions of the subterraneanformation that contain shale to prevent the production of such fines. Insome instances, shale may be isolated with blank pipe (e.g., pipe thatdoes not comprise slots or other holes on its exterior surface orientedto the well bore walls). Exposed shale may be hydraulically isolated byplacing blank pipe across these intervals and isolating the annulususing open hole packers. Conventional mechanical, hydraulic,hydrostatic, inflatable, or swelling elastomer packers may provideannular isolation for this purpose. Some examples of open hole packersinclude WIZARD® III Packer and SWELLPACKER™, both of which are availablefrom Halliburton Energy Services, Inc. in Carrollton, Tex.

Effective treatment of long intervals can be further complicated byvariable reservoir properties such as porosity, permeability, and porepressure. The term “reservoir” as used herein refers to a subsurfacebody of rock having sufficient porosity and permeability to store andtransmit fluids such as gas, oil, or water. For instance, a longinterval may include variable high permeability portions. In somesituations, high permeability portions may act as thief zones taking thebulk of the treatment fluids, where low permeability, higher pressuredzones may not accept any of the treatment fluids. Chemical diversiontechniques are often used in stimulation treatments and are focused onplugging the high perm zones to help force fluid flow into the low permzones. Uniform placement of treating fluids under these conditions andusing these solutions can be difficult and unreliable. As used herein,the term “treatment,” or “treating,” refers to any subterraneanoperation performed in conjunction with a desired function and/or for adesired purpose. The term “treatment,” or “treating,” does not imply anyparticular action. As used herein, the term “treatment fluid” refers toany fluid that may be used in a subterranean application in conjunctionwith a desired function and/or for a desired purpose. The term“treatment fluid” does not imply any particular action by the fluid orany component thereof.

SUMMARY

The present invention relates to methods, compositions, systems, anddevices useful in treating subterranean formations and, moreparticularly, to consolidating potentially relatively unconsolidatedportions of subterranean formations and minimizing particulate migrationover long intervals. More specifically, the present invention relates tomethods for applying consolidating agent systems over at least a portionof a long interval in a subterranean well bore that may be horizontal,vertical, deviated, or otherwise nonlinear.

In one embodiment, the present invention provides a method comprising:providing a well bore comprising an open hole section of about 30 feetor more that comprises a filter cake neighboring at least a portion of areservoir in a subterranean formation; placing a flow distributionsystem in the open hole section, the flow distribution system comprisinga plurality of annular barriers; compromising the integrity of thefilter cake; activating at least one of the annular barriers; andplacing a consolidating agent system into the formation to at leastpartially reduce particulate migration in the open hole section.

In one embodiment, the present invention provides a method comprising:providing a well bore comprising an open hole section of about 30 feetor more that comprises a filter cake neighboring at least a portion of areservoir; allowing the integrity of at least a portion of the filtercake to become compromised; and treating at least a portion of the openhole section with a consolidating agent system in a single stageoperation so as to at least partially reduce particulate migration inthe open hole section.

In one embodiment, the present invention provides a method comprising:providing a well bore comprising an open hole section of about 30 feetor more that comprises a filter cake neighboring a reservoir; allowingthe integrity of the filter cake to become compromised; and placing aconsolidating agent system into the formation in a single stageoperation so as to at least partially reduce particulate migration in aportion of the open hole section.

In one embodiment, the present invention provides a method comprising:providing a well bore comprising an open hole section of about 30 feetor more having a filter cake neighboring at least a portion of areservoir in a subterranean formation; placing a flow distributionsystem in the open hole section, the flow distribution systemcomprising: a flow distributor; a borehole support assembly; asuspension tool; and a service assembly comprising a flow positioner;allowing the integrity of the filter cake to become compromised;removing the service assembly from the well bore; installing completiontubing; and placing a consolidating agent system into the formation toat least partially reduce particulate migration in the open holesection.

In one embodiment, the present invention provides a method comprising:drilling a well bore in a subterranean formation, the well borecomprising an open hole section of about 30 feet or more that comprisesa filter cake neighboring at least a portion of a reservoir in theformation; placing a flow distribution system in the open hole section,the flow distribution system comprising: a borehole support assembly; asuspension tool; and a service assembly comprising a flow positioner;allowing the integrity of the filter cake to become compromised;removing the service assembly from the well bore; installing completiontubing; placing a consolidating agent system into the formation to atleast partially reduce particulate migration in the open hole section;and placing the well in service.

In one embodiment, the present invention provides a method comprising:providing a well bore comprising an open hole section that comprises afilter cake neighboring at least a portion of a reservoir in aformation; placing a flow distribution system in the open hole section,the flow distribution system comprising: a borehole support assembly; asuspension tool; and a service assembly comprising a flow positioner;allowing the integrity of the filter cake to become compromised; placinga consolidating agent system into the formation to at least partiallyreduce particulate migration in the open hole section; removing theservice assembly from the well bore; installing completion tubing; andplacing the well in service.

The features and advantages of the present invention will be readilyapparent to those skilled in the art. While numerous changes may be madeby those skilled in the art, such changes are within the spirit of theinvention.

BRIEF DESCRIPTION OF THE DRAWINGS

These drawings illustrate certain aspects of some of the embodiments ofthe present invention, and should not be used to limit or define theinvention.

FIG. 1 a is a side view showing one embodiment of a flow distributionsystem within a well bore.

FIG. 1 b is side view of the embodiment of FIG. 1 a, showing placementof a filter cake degradation fluid.

FIG. 1 c is a side view of the embodiment of FIG. 1 a, after a serviceassembly has been removed from the well bore.

FIG. 1 d is a side view of the embodiment of FIG. 1 a, after a filtercake has been compromised, and annular barriers have activated.

FIG. 1 e is a side view of the embodiment of FIG. 1 a, with completiontubing in place, showing placement of a consolidating agent system.

FIG. 1 f is a side view of the embodiment of FIG. 1 a, after placementof the consolidating agent system.

FIG. 1 g is a side view of the embodiment of FIG. 1 a, showing aproduction operation.

FIG. 1 h is a side view of the embodiment of FIG. 1 a, showing aninjection operation.

FIG. 2 a is a side view showing another embodiment of a flowdistribution system within a well bore.

FIG. 2 b is side view of the embodiment of FIG. 2 a, showing placementof a filter cake degradation fluid.

FIG. 2 c is a side view of the embodiment of FIG. 2 a, after a filtercake has been compromised and annular barriers have activated, showingplacement of a consolidating agent system.

FIG. 2 d is a side view of the embodiment of FIG. 2 a, after placementof the consolidating agent system.

FIG. 2 e is a side view of the embodiment of FIG. 2 a, with completiontubing in place.

FIG. 2 f is a side view of the embodiment of FIG. 2 a, showing aproduction operation.

FIG. 2 g is a side view of the embodiment of FIG. 2 a, showing aninjection operation.

FIG. 3 a is a side view showing yet another embodiment of a flowdistribution system within a well bore.

FIG. 3 b is side view of the embodiment of FIG. 3 a, showing placementof a filter cake degradation fluid.

FIG. 3 c is a side view of the embodiment of FIG. 3 a, after a filtercake has been compromised.

FIG. 3 d is a side view of the embodiment of FIG. 3 a, showing placementof a consolidating agent system.

FIG. 3 e is a side view of the embodiment of FIG. 3 a, after placementof the consolidating agent system.

FIG. 3 f is a side view of the embodiment of FIG. 3 a, with completiontubing in place.

FIG. 3 g is a side view of the embodiment of FIG. 3 a, showing aproduction operation.

FIG. 3 h is a side view of the embodiment of FIG. 3 a, showing aninjection operation.

DETAILED DESCRIPTION

The present invention relates to methods, compositions, systems, anddevices useful in treating subterranean formations and, moreparticularly, to consolidating potentially relatively unconsolidatedportions of subterranean formations and minimizing particulate migrationover long intervals. More specifically, the present invention relates tomethods for applying consolidating agent systems over at least a portionof a long interval in a subterranean well bore that may be horizontal,vertical, deviated, or otherwise nonlinear.

The methods of the present invention may be applicable to horizontal,vertical, deviated, or otherwise nonlinear well bores in any type ofsubterranean formation. The methods may be applicable to injection wellsas well as production wells, including hydrocarbon wells. One of themany potential advantages of the methods of the present invention (manyof which are not discussed or eluded to herein) is that consolidatingagent systems may be placed over at least a portion of a long intervalof an open hole section to at least partially control particulatemigration, which otherwise may negatively impact the conductivity of theformation. Referring generally to the Figures, in some embodiments, aconsolidating agent system may be placed, covering an entire or amajority of a desired interval in a single stage. In some embodiments,single stage placement may be possible via flow distribution system 100,which limits flow out of any one point of the screen or other boreholesupport assembly 102, thus providing what is considered to be effectivetreatment over a relatively long interval.

As used herein, the term “open hole section” refers to any portion of awell bore that is either uncased or is perforated. This may include, butis not limited to an uncased section following a cased section, or aperforated section.

With reference to the figures in some instances, in some embodiments,the methods of the present invention may assist in placing consolidatingagent system 106, which may include any suitable consolidating agentsystem (e.g., those discussed below). This placement can be used forrelative uniform or near-uniform placement of the consolidating agentsystems over at least a portion of a long interval of an open holesection to provide at least some degree of particulate migrationcontrol. Examples of uniform or near-uniform placement include, but arenot limited to, when a consolidating agent is placed into the reservoiraround the well bore at a chosen minimum depth of placement along anentire chosen interval (e.g., a depth of equal to or greater than ½ wellbore diameter). Some intervals may be around 30 feet or more up to inexcess of 10,000 feet as dictated by the ability to drill longerintervals. Any length of interval between these is disclosed herein.Using the methods of the present invention, in some embodiments, wellbore tubulars, casing, liners, slotted liners, pre-drilled liners,perforated liners, or screens can be used to provide borehole support.Additionally, at least in some embodiments, these methods providedherein may make it possible to eliminate gravel pack treatments, whichmay help to simplify the system architecture and installationprocedures, possibly saving rig time and expense.

In one embodiment, the present invention provides a method comprising:providing a well bore comprising an open hole section of about 30 feetor more that comprises a filter cake neighboring at least a portion of areservoir in a subterranean formation; placing a flow distributionsystem in the open hole section, the flow distribution system comprisinga plurality of annular barriers; compromising the integrity of thefilter cake; activating at least one of the annular barriers; andplacing a consolidating agent system into the formation to at leastpartially reduce particulate migration in the open hole section.

In one embodiment, the present invention provides a method comprising:providing a well bore comprising an open hole section of about 30 feetor more that comprises a filter cake neighboring at least a portion of areservoir; allowing the integrity of at least a portion of the filtercake to become compromised; and treating at least a portion of the openhole section with a consolidating agent system in a single stageoperation so as to at least partially reduce particulate migration inthe open hole section.

In one embodiment, the present invention provides a method comprising:providing a well bore comprising an open hole section of about 30 feetor more that comprises a filter cake neighboring a reservoir; allowingthe integrity of the filter cake to become compromised; and placing aconsolidating agent system into the formation in a single stageoperation so as to at least partially reduce particulate migration in aportion of the open hole section.

In one embodiment, the present invention provides a method comprising:providing a well bore comprising an open hole section of about 30 feetor more having a filter cake neighboring at least a portion of areservoir in a subterranean formation; placing a flow distributionsystem in the open hole section, the flow distribution systemcomprising: a flow distributor; a borehole support assembly; asuspension tool; and a service assembly comprising a flow positioner;allowing the integrity of the filter cake to become compromised;removing the service assembly from the well bore; installing completiontubing; and placing a consolidating agent system into the formation toat least partially reduce particulate migration in the open holesection.

In one embodiment, the present invention provides a method comprising:drilling a well bore in a subterranean formation, the well borecomprising an open hole section of about 30 feet or more that comprisesa filter cake neighboring at least a portion of a reservoir in theformation; placing a flow distribution system in the open hole section,the flow distribution system comprising: a borehole support assembly; asuspension tool; and a service assembly comprising a flow positioner;allowing the integrity of the filter cake to become compromised;removing the service assembly from the well bore; installing completiontubing; placing a consolidating agent system into the formation to atleast partially reduce particulate migration in the open hole section;and placing the well in service.

In one embodiment, the present invention provides a method comprising:providing a well bore comprising an open hole section that comprises afilter cake neighboring at least a portion of a reservoir in aformation; placing a flow distribution system in the open hole section,the flow distribution system comprising: a borehole support assembly; asuspension tool; and a service assembly comprising a flow positioner;allowing the integrity of the filter cake to become compromised; placinga consolidating agent system into the formation to at least partiallyreduce particulate migration in the open hole section; removing theservice assembly from the well bore; installing completion tubing; andplacing the well in service.

A filter cake may be placed on the surfaces of the subterraneanformation by a drilling fluid, a drill-in fluid, or another suitablefluid as a result of drilling the well bore. Filter cakes can also bedeposited in a cased and perforated well or open hole well by the use offluid loss pills containing solids and/or polymer solutions that willbridge off and form a filter cake as the fluid leaks into the formation.The components of the filter cake may vary depending on the compositionof the drilling fluid, drill-in fluid, or a fluid loss remediationtreatment (e.g., a fluid loss pill). Thus, the method used to compromisethe integrity of the filter cake should vary.

Referring to the figures for nonlimiting illustrations of certainaspects of some of the methods of the present invention, flowdistribution system 100 may be a bottom hole assembly or any otherdevice or system for delivering material into the well. In someembodiments, flow distribution system 100 may be an integral part of aconventional sand control screen. Alternatively, flow distributionsystem 100 may be installed with wash pipe 110, allowing flow exitingwash pipe 110 to be evenly distributed along the length of the intervalfor uniform treatment. Flow distribution system 100 with consolidationmay increase feasibility of slim bore sand control completions, even invery highly productive wells.

Referring now to the exemplary embodiments of FIGS. 1 a-1 h, flowdistribution system 100 is illustrated in well bore 114. The wellassociated with well bore 114 may be for production or for injection.For example, after being treated with consolidating agent system 106(shown in FIGS. 1 e-1 h), well bore 114 may produce hydrocarbons. Wellbore 114 may have open hole section 116. Open hole section 116 may havefilter cake 112 in place prior to placement of flow distribution system100. Filter cake 112 and/or open hole section 116 may neighbor reservoir108. Reservoir 108 may comprise oil, gas, other hydrocarbons, or othermaterials for which production is desired. Reservoir 108 may comprisewater or other aqueous fluids as well. Alternatively, reservoir 108 maybe used to store or otherwise inject material.

Depending on the particular device(s) selected, flow distribution system100 may include flow distributor 104, borehole support assembly 102,optional annular barriers 120, suspension tool 122, and service assembly124. Flow distribution system 100 may also include optional fluid lossvalve 126. Flow distribution system 100 may be placed in well bore 114via any of a number of devices and/or systems. For example, flowdistribution system 100 may be run into well bore 114 on tubing (e.g.,production tubing). Other options for placing flow distribution system100 include a work string, a drill string, a coiled tubing string, orany other means for placing tools into well bores. Flow distributionsystem 100 may be assembled at the surface and may include blank pipeand annular barriers 120 to isolate exposed shale in the open holesection 116. Wash pipe 110, suspension tool 122, fluid loss valve 126,and borehole support assembly 102 may allow spotting and circulation offluids. After flow distribution system 100 is assembled, it may beplaced in open hole section 116 of well bore 114, and suspension tool122 may be set.

If included, flow distributor 104 may be any device associated with aformation to well bore flow path, which can cause a pressure dropsufficiently high relative to the overall pressure drop along the lengthof well bore 114 that results in substantially uniform flow distributionamongst the formation to well bore flow paths along the length of thewell. Flow distributor 104 may be any of a number of different devices,including, but not limited to, an inflow control device, an outflowcontrol device, a port or other orifice, a shunt tube, a poppet valve, achoke, a tortuous path, a nozzle-type device, a helix-type device, or atube-type device. Alternatively, a series of nozzles and/or tubes may beused to achieve the desired pressure loss. Flow distributor 104 may alsoinclude one or more infinitely variable control valves or variablecontrol valves that may be controlled mechanically, hydraulically, orelectronically. Any device capable of selectively passing materialtherethrough may be suitable for use as flow distributor 104, forexample, EQUIFLOW™ screens, available from Halliburton Energy Services,Inc. in Duncan, Okla. Flow distributor 104 may also be an adjustableflow path inflow control device or a combination of an inflow controldevice and another device. For adjustable flow, flow distributor 104 mayhave a number of positions, including full open flow, injection control,and production control of unwanted fluids. To further enhance theperformance of flow distribution system 100, flow distributor 104 mayinclude two or more ports. One or more of the ports may be fitted with aone-way check valve so that flow distributor 104 will allow for improveddiversion prior to completion of the well, and may act as an inflowcontrol device equalizing flow with less pressure drop duringproduction. Flow distributor may be part of service assembly 124,removed with wash pipe 110, or it may stay in place.

If included, borehole support assembly 102 may be used in combinationwith wash pipe 110 or independently to support, filter, or isolate. Forexample, borehole support assembly 102 may prevent sand-out or collapseof the borehole by providing structural support if the formationplastically fails and conforms to the shape of assembly. Alternatively,borehole support assembly 102 may prevent formation material fromentering production. In another application, borehole support assembly102 may isolate to avoid undesirable areas, such as shale. Whileborehole support assembly 102 is shown as a screen, it may alternativelybe a slotted liner, a perforated pipe, or a blank pipe, for example.

Optional annular barriers 120 may be annular isolation devices thatprovide at least some degree of isolation, which may be useful foruniform application of fluids. Annular barriers 120 may be activated byany of a number of different methods, depending on the specific type.For example, annular barriers 120 may activate hydrostatically,hydraulically, mechanically, inflatably, or via contact with anactivating material. In one embodiment, annular barriers 120 may beswell packers that activate upon contact with a particular fluid. Insome embodiments, the annular isolation device responds to a fluidpresent within the subterranean formation to substantially isolate atleast a portion of the open hole section. Swell packers are relativelysimple to install, generally have no operational requirement and arelatively long seal area that can seal in bad hole conditions, and theyare thought to be highly reliable. In one embodiment, the particularfluid for activating the swell packers may be filter cake degradationfluid 118 (discussed below). This allows annular barriers 120 toactivate around the same time as filter cake 112 degrades. Since filtercake degradation fluid 118 may activate swell packers, it may containadditives to cause this reaction to occur more rapidly. Hydraulic orhydrostatic packers may be used in conjunction with swell packers toeliminate waiting time associated with swell packers. This may beparticularly useful when valuable rig time is spent waiting on swellpackers to set.

As further discussed below, self-diverting fluids may be used as analternative to an annular barrier to better distribute the flow of theconsolidating agent system within the well bore, for example.Self-diverting fluids are thought to allow a circulation squeezeapproach to ensure contact with well bore 114, without the need formechanical or other traditional annular barriers 120. If, however,annular barriers 120 are still used, they may not activate until afterthe well is in service. The use of self-diverting fluid 132 may allowfor the omission of flow distributors 104, as discussed below withrespect to FIGS. 3 a-3 g. Self-diverting fluid 132 may be any of anumber of fluids capable of acting as diverting fluids. Suitableexamples include any known self-diverting fluid such as foamed fluidswith 50% to 90% quality (gas content) or shear thinning gelled fluidssuch as xanthan gel systems or other such polymeric systems. An exampleof a self-diverting fluid is a 50%-to-90%-quality nitrogen foam. Somecommercially available examples of suitable diverting fluids includeAQUALINEAR™ or LO-GUARD™ (available from Halliburton Energy Services,Inc. in Duncan, Okla.).

If included, as illustrated, suspension tool 122 should at leastpartially support borehole support assembly 102 in well bore 114.Suspension tool 122 may be a packer, a screen hanger, a liner hangerassembly, a gravel pack packer, or any other such supporting device.

Service assembly 124 may be part of flow distribution system 100 and canbe used to service the well prior to placing it in production. Oneexemplary embodiment of service assembly 124, as illustrated in FIGS. 1a-1 h, includes flow positioner 128 and may include wash pipe 110. Flowpositioner 128 may be any device to selectively position flow. Flowpositioner 128 may be a multi-positioning tool, a crossover tool, or anyother device allowing selective passage. For example, a VERSA-TRIEVE®Packer/Multi-Position Tool (available from Halliburton Energy Services,Inc. in Carrollton, Tex.) may be used in multiple configurations. Forexample, in the squeeze position, this flow positioner establishes flowpaths necessary to squeeze fluid into the formation. In upper and lowercirculating positions, this flow positioner circulates fluid across theformation interval, through borehole support assembly 102, then back upthe tubing/casing annulus. In the reverse circulating position, thisflow positioner circulates reverse fluids down the annulus and back upthe tubing. It can also be used to circulate down the tubing to spotfluid in place. Generally, raising and lowering the multi-position toolrelative to suspension tool 122 provides these changes of flow path.

If included, wash pipe 110 provides a temporary internal conduit, andmay include cup packers 134 (shown in FIGS. 2a-2g) for selectiveinjection, preventing cross flow in the annulus. While wash pipe 110 isshown in some illustrated embodiments, it may be omitted in otherembodiments.

If included, fluid loss valve 126 may prevent fluid loss in alternativeembodiments such as when service assembly 124 is not present in wellbore 114. The fluid loss valve 126 may be any of a number of valves,including, but not limited to, a ceramic flapper valve.

According to the illustrated embodiment, flow distribution system 100may be placed in open hole section 116 and can be used for a number ofoperations. For example, flow distribution system 100 may first be usedin a method aimed at compromising the integrity of filter cake 112, asillustrated in FIGS. 1 b-1 d. This may involve placing a filter cakedegradation fluid 118 in contact with filter cake 100. As illustrated inFIG. 1 b, in some embodiments, filter cake degradation fluid 118 may bepumped down through wash pipe 110, and into the annulus, allowing filtercake degradation fluid 118 to contact filter cake 112. Over time, filtercake degradation fluid 118 may react with filter cake 112, causingfilter cake 112 to become less effective at preventing fluids frominteracting with the subterranean formation. Thinning and/or holes mayform in filter cake 112, thus allowing fluids to pass through theformation more easily. This process is generally termed herein as“compromising the integrity of the filter cake” or “degrading the filtercake.” The term does not imply any particular degree of compromise ordegradation.

Filter cake degradation fluid 118 may have certain characteristics,depending on the composition of the filter cake. In some embodiments,filter cake degradation fluid 118 may not be necessary, for example,where the filter cake is largely self-degrading. If the filter cakelargely comprises acid-soluble bridging agents, such as calciumcarbonate, then the filter cake degradation fluid 118 should comprise anacid or an acid precursor capable of interacting with those acid-solublebridging agents in such a way as to compromise the integrity of thefilter cake in a desirable manner. Alternatively, or in addition to suchacids, if the filter cake comprises a polymeric component (e.g., apolymeric component corresponding to gelling agent polymers found in thedrilling fluid such as xanthan, guar, cellulose derivatives, syntheticpolymers, and the like), materials capable of degrading those polymersshould be included in filter cake degradation fluid 118. These mayinclude oxidizers or bases, or even some enzymes in certain situations.In some embodiments, filter cake degradation fluid 118 may be an aqueousfluid.

Filter cake degradation fluid 118 may comprise an acid precursor thatgenerates an acid that may be capable of interacting with acid-solubleportions in the filter cake. U.S. Pat. No. 7,140,438, the relevantportion of which is herein incorporated by reference, describes one suchsystem utilizing acids generated from orthoesters to degrade filter cakecomponents. Suitable filter cake degradation fluids for filter cakedegradation fluid 118 include, but are not limited to, delayed acidrelease systems (e.g., N-FLOW™, available from Halliburton EnergyServices, Inc. in Duncan, Okla.); delayed release acid systems having achemical trigger for predetermined delays in degrading the filter cake,which may be advantageous in certain circumstances (e.g., ACCUBREAK®,available from Halliburton Energy Services, Inc. in Duncan, Okla.);oil-based acid systems (e.g., OSA™, available from Halliburton EnergyServices, Inc. in Duncan, Okla.); slow-reacting oil soluble acid systemsfor oil-based or aqueous-based drilling or drill-in fluids; acidsolutions; enzyme solutions; and base solutions; or combinations ofthese systems; and derivatives of these systems. One example of filtercake degradation fluid 118 is a fluid comprising an oil soluble acid,which includes a slow-reacting organic acid that can perform multiplefunctions. The acid may remove calcium carbonate and help break anypolymer used in filter cake 112. Additionally, the oil base fluid mayactivate annular barriers 120.

Other examples of suitable methods and compositions for compromising theintegrity of a filter cake are described in U.S. Pat. No. 7,195,068, therelevant disclosure of which is incorporated by reference. Methods aredescribed therein of degrading a filter cake comprising an acid-solubleportion and a polymeric portion in a subterranean formation comprisingthe steps of: introducing a filter cake degradation compositioncomprising a delayed-release acid component and a delayed-releaseoxidizer component to a well bore penetrating the subterraneanformation; allowing the delayed-release acid component to release anacid derivative and the delayed-release oxidizer component to release anacid-consuming component; allowing the acid-consuming component tointeract with the acid derivative to delay a reaction between at least aportion of the acid derivative and at least a portion of theacid-soluble portion of the filter cake and to produce hydrogenperoxide; allowing the acid derivative to degrade at least a portion ofthe acid-soluble portion of the filter cake after a delay period; andallowing the hydrogen peroxide to degrade at least a portion of thepolymeric portion of the filter cake. Other methods of compromising theintegrity of a filter cake are disclosed in U.S. Patent ApplicationPublication Nos. 2007/0078064, 2006/0105917, 2006/0105918, and2006/0205608, the relevant disclosures of which are hereby incorporatedby reference.

In some embodiments, the filter cake may be self-degrading, in that itcomprises self-degrading bridging agents. Such self-degrading bridgingagents usually comprise a degradable material. Examples ofself-degrading bridging agents include, but are not limited to, thosecomprising: ortho esters (which may be referred to as ortho ethers);poly(orthoesters) (which may be referred to as poly(ortho ethers);aliphatic polyesters; lactides; poly(lactides); glycolides;poly(glycolides); poly(α-caprolactone); poly(hydroxybutyrate);substantially water-insoluble anhydrides; poly(anhydrides); andpoly(amino acids). Other self-degrading bridging agents may be suitableas well.

In some embodiments, the annular barriers may be activated before theintegrity of the filter cake becomes substantially compromised.

In the embodiment of FIGS. 1 a-1 h, fluid loss valve 126 may beactivated (e.g., closed) as service assembly 124 is removed, or it maybe activated afterward. FIG. 1 c illustrates flow distribution system100 after removal of service assembly 124 and activation of fluid lossvalve 126, but before filter cake degradation fluid 118 has had time toreact with filter cake 112 and annular barriers 120. While theembodiments of FIGS. 1 a-1 h illustrate filter cake degradation fluid118, it may be omitted in other embodiments. FIG. 1 d illustrates flowdistribution system 100 after some time has passed, such that filtercake 112 has been compromised and annular barriers 120 have activated.In some embodiments, these reactions occur within the time it takes forthe service assembly 124 to be removed and the completion tubing 130 tobe installed. Thus, little or no additional wait time would be requiredbefore pumping consolidating agent system 106 into the formation.Alternatively, filter cake 112 and annular barriers 120 may reactwithout filter cake degradation fluid 118. For example, annular barriers120 activate upon exposure to hydrocarbons in well bore 114. Filter cake112 may comprise a sufficient concentration of self-degrading bridgingagents, and therefore, filter cake degradation fluid 118 may not berequired. One of ordinary skill in the art, with the benefit of thisdisclosure, will recognize whether filter cake degradation fluid 118 isneeded and, if so, what its composition should be based on thecomposition of the filter cake at issue.

In the embodiment of FIGS. 1 a-1 h, as soon as service assembly 124 isremoved, completion tubing 130 and upper completion equipment may beinstalled. Completion tubing 130 may be any type of tubular suitable foruse in completing a well. For example, completion tubing 130 may includea number of pipe joints or it may include coiled tubing. Installation ofcompletion tubing 130 may cause fluid loss valve 126 to rupture, suchthat it deactivates simultaneously with installation of completiontubing 130. Alternatively, pressure or any other means may deactivatefluid loss valve 126 at any time.

As illustrated in FIG. 1 e, consolidating agent system 106 may be placedby pumping down through completion tubing and out through flowdistribution system 100, using borehole support assembly 102 to equalizeflow over the entire desired interval length. Consolidating agent system106 may be over-displaced, and time may be allowed for it to cure orreact prior to placing the well in service.

Consolidating agent system 106 may comprise any suitable consolidatingagent system that is useful for controlling particulate migration to thedesired degree. The consolidating agent system, in some embodiments,enables consolidation to occur only at the points of contact betweenparticles. For example, in some embodiments, the materials will attachto the particulates and not fill or seal the porosity of the formation(e.g., resins, tackifiers, silyl-modified polyamide compounds,crosslinkable aqueous polymer compositions, consolidating agentemulsions, polymerizable organic monomer compositions, and the like).Optionally, consolidating agent system 106 may include pre-flush and/ora post-flush step.

In some embodiments, it may be desirable to utilize a pre-flush fluidprior to the placement of the consolidating agent in a subterraneanformation, inter alia, to remove excess fluids from the pore spaces inthe subterranean formation, to clean the subterranean formation, etc.Examples of suitable pre-flush fluids include, but are not limited to,aqueous fluids, solvents, and surfactants capable of altering thewetability of the formation surface. Examples of suitable pre-flushsolvents may include mutual solvents such as MUSOL® and N-VER-SPERSE A™,both commercially available from Halliburton Energy Services, Inc., ofDuncan, Okla. An example of a suitable pre-flush surfactant may alsoinclude an ethoxylated nonylphenol phosphate ester such as ES-5™, whichis commercially available from Halliburton Energy Services, Inc., ofDuncan, Okla. Additionally, in those embodiments where the consolidatingagent comprises a resin composition, it may be desirable to include ahardening agent in a pre-flush fluid.

Additionally, in some embodiments, it may be desirable to utilize apost-flush fluid subsequent to the placement of the consolidating agentin a subterranean formation, inter alia, to displace excessconsolidating agent from the near well bore region. Examples of suitablepost-flush fluids include, but are not limited to, aqueous fluids,surfactants, solvents, or gases (e.g., nitrogen), or any combinationthereof. Additionally, in some embodiments, in may be desirable toinclude a hardening agent in the post-flush fluid. For example, certaintypes of resin compositions, including, but not limited to, furan-basedresins, urethane resins, and epoxy-based resins, may be catalyzed with ahardening agent placed in a post-flush fluid.

The consolidating agents suitable for use in the methods of the presentinvention generally comprise any compound that is capable of minimizingparticulate migration and/or modifying the stress-activated reactivityof surfaces in subterranean formations. In some embodiments, theconsolidating agent may comprise a consolidating agent chosen from thegroup consisting of: non-aqueous tackifying agents; aqueous tackifyingagents; resins; silyl-modified polyamide compounds; crosslinkableaqueous polymer compositions; and consolidating agent emulsions.Combinations of these also may be suitable.

The type and amount of consolidating agent included in a particularmethod of the invention may depend upon, among other factors, thecomposition and/or temperature of the subterranean formation, thechemical composition of formations fluids, the flow rate of fluidspresent in the formation, the effective porosity and/or permeability ofthe subterranean formation, pore throat size and distribution, and thelike. Furthermore, the concentration of the consolidating agent can bevaried, inter alia, to either enhance bridging to provide for a morerapid coating of the consolidating agent or to minimize bridging toallow deeper penetration into the subterranean formation. It is withinthe ability of one skilled in the art, with the benefit of thisdisclosure, to determine the type and amount of consolidating agent toinclude in the methods of the present invention to achieve the desiredresults.

The consolidating agents suitable for use in the methods of the presentinvention may be provided in any suitable form, including in a particleform, which may be in a solid form and/or a liquid form. In thoseembodiments where the consolidating agent is provided in a particleform, the size of the particle can vary widely. In some embodiments, theconsolidating agent particles may have an average particle diameter ofabout 0.01 micrometers (“μm”) to about 300 μm. In some embodiments, theconsolidating agent particles may have an average particle diameter ofabout 0.01 μm to about 100 μm. In some embodiments, the consolidatingagent particles may have an average particle diameter of about 0.01 μmto about 10 μm. The size distribution of the consolidating agentparticles used in a particular composition or method of the inventionmay depend upon several factors, including, but not limited to, the sizedistribution of the particulates present in the subterranean formation,the effective porosity and/or permeability of the subterraneanformation, pore throat size and distribution, and the like.

In some embodiments, it may be desirable to use a consolidating agentparticle with a size distribution such that the consolidating agentparticles are placed at contact points between formation particulates.For example, in some embodiments, the size distribution of theconsolidating agent particles may be within a smaller size range, e.g.,of about 0.01 μm to about 10 μm. It may be desirable in some embodimentsto provide consolidating agent particles with a smaller particle sizedistribution, inter alia, to promote deeper penetration of theconsolidating agent particles through a body of unconsolidatedparticulates or in low permeability formations.

In other embodiments, the size distribution of the consolidating agentparticles may be within a larger range, e.g. of about 30 μm to about 300μm. It may be desirable in some embodiments to provide consolidatingagent particles with a larger particle size distribution, inter alia, topromote the filtering out of consolidating agent particles at or nearthe spaces between neighboring unconsolidated particulates or in highpermeability formations. A person of ordinary skill in the art, with thebenefit of this disclosure, will be able to select an appropriateparticle size distribution for the consolidating agent particlessuitable for use in the present invention and will appreciate thatmethods of creating consolidating agent particles of any relevant sizeare well known in the art.

In some embodiments of the present invention, the consolidating agentmay comprise a non-aqueous tackifying agent. A particularly preferredgroup of non-aqueous tackifying agents comprises polyamides that areliquids or in solution at the temperature of the subterranean formationsuch that they are, by themselves, nonhardening when introduced into thesubterranean formation. A particularly preferred product is acondensation reaction product comprised of a commercially availablepolyacid and a polyamine. Such commercial products include compoundssuch as mixtures of dibasic acids containing some trimer and higheroligomers and also small amounts of monomer acids that are reacted withpolyamines. Other polyacids include trimer acids, synthetic acidsproduced from fatty acids, maleic anhydride, acrylic acid, and the like.Combinations of these may be suitable as well. Such acid compounds arecommercially available from companies such as Union Camp, Chemtall, andEmery Industries. The reaction products are available from, for example,Champion Technologies, Inc.

Additional compounds which may be used as non-aqueous tackifying agentsinclude liquids and solutions of, for example, polyesters,polycarbonates, silyl-modified polyamide compounds, polycarbamates,urethanes, natural resins such as shellac, and the like. Combinations ofthese may be suitable as well.

Other suitable non-aqueous tackifying agents are described in U.S. Pat.Nos. 5,853,048 and 5,833,000, both issued to Weaver, et al., and U.S.Patent Publication Nos. 2007/0131425 and 2007/0131422, the relevantdisclosures of which are herein incorporated by reference.

Non-aqueous tackifying agents suitable for use in the present inventionmay either be used such that they form a nonhardening coating on asurface or they may be combined with a multifunctional material capableof reacting with the non-aqueous tackifying agent to form a hardenedcoating. A “hardened coating” as used herein means that the reaction ofthe tackifying compound with the multifunctional material should resultin a substantially non-flowable reaction product that exhibits a highercompressive strength in a consolidated agglomerate than the tackifyingcompound alone with the particulates. In this instance, the non-aqueoustackifying agent may function similarly to a hardenable resin.

Multifunctional materials suitable for use in the present inventioninclude, but are not limited to, aldehydes; dialdehydes such asglutaraldehyde; hemiacetals or aldehyde releasing compounds; diacidhalides; dihalides such as dichlorides and dibromides; polyacidanhydrides; epoxides; furfuraldehyde; aldehyde condensates; andsilyl-modified polyamide compounds; and the like; and combinationsthereof. Suitable silyl-modified polyamide compounds that may be used inthe present invention are those that are substantially self-hardeningcompositions capable of at least partially adhering to a surface or to aparticulate in the unhardened state, and that are further capable ofself-hardening themselves to a substantially non-tacky state to whichindividual particulates such as formation fines will not adhere to, forexample, in formation or proppant pack pore throats. Such silyl-modifiedpolyamides may be based, for example, on the reaction product of asilating compound with a polyamide or a mixture of polyamides. Thepolyamide or mixture of polyamides may be one or more polyamideintermediate compounds obtained, for example, from the reaction of apolyacid (e.g., diacid or higher) with a polyamine (e.g., diamine orhigher) to form a polyamide polymer with the elimination of water.

In some embodiments of the present invention, the multifunctionalmaterial may be mixed with the tackifying compound in an amount of about0.01% to about 50% by weight of the tackifying compound to effectformation of the reaction product. In other embodiments, themultifunctional material is present in an amount of about 0.5% to about1% by weight of the tackifying compound. Suitable multifunctionalmaterials are described in U.S. Pat. No. 5,839,510 issued to Weaver, etal., the relevant disclosure of which is herein incorporated byreference.

Aqueous tackifying agents suitable for use in the present invention areusually not generally significantly tacky when placed onto aparticulate, but are capable of being “activated” (e.g., destabilized,coalesced and/or reacted) to transform the compound into a sticky,tackifying compound at a desirable time. Such activation may occurbefore, during, or after the aqueous tackifier agent is placed in thesubterranean formation. In some embodiments, a pretreatment may be firstcontacted with the surface of a particulate to prepare it to be coatedwith an aqueous tackifier agent. Suitable aqueous tackifying agents aregenerally charged polymers that comprise compounds that, when in anaqueous solvent or solution, will form a nonhardening coating (by itselfor with an activator) and, when placed on a particulate, will increasethe continuous critical resuspension velocity of the particulate whencontacted by a stream of water. The aqueous tackifier agent may enhancethe grain-to-grain contact between the individual particulates withinthe formation (be they proppant particulates, formation fines, or otherparticulates), helping bring about the consolidation of the particulatesinto a cohesive, flexible, and permeable mass.

Suitable aqueous tackifying agents include any polymer that can bind,coagulate, or flocculate a particulate. Also, polymers that function aspressure-sensitive adhesives may be suitable. Examples of aqueoustackifying agents suitable for use in the present invention include, butare not limited to: acrylic acid polymers; acrylic acid ester polymers;acrylic acid derivative polymers; acrylic acid homopolymers; acrylicacid ester homopolymers (such as poly(methyl acrylate), poly (butylacrylate), and poly(2-ethylhexyl acrylate)); acrylic acid esterco-polymers; methacrylic acid derivative polymers; methacrylic acidhomopolymers; methacrylic acid ester homopolymers (such as poly(methylmethacrylate), poly(butyl methacrylate), and poly(2-ethylhexylmethacrylate)); acrylamido-methyl-propane sulfonate polymers;acrylamido-methyl-propane sulfonate derivative polymers;acrylamido-methyl-propane sulfonate co-polymers; and acrylicacid/acrylamido-methyl-propane sulfonate co-polymers; derivativesthereof, and combinations thereof. The term “derivative” as used hereinrefers to any compound that is made from one of the listed compounds,for example, by replacing one atom in the base compound with anotheratom or group of atoms. Methods of determining suitable aqueoustackifying agents and additional disclosure on aqueous tackifying agentscan be found in U.S. patent application Ser. No. 10/864,061, filed Jun.9, 2004 and U.S. patent application Ser. No. 10/864,618, filed Jun. 9,2004, the relevant disclosures of which are hereby incorporated byreference.

Some suitable tackifying agents are described in U.S. Pat. No. 5,249,627by Harms, et al., the relevant disclosure of which is incorporated byreference. Harms discloses aqueous tackifying agents that comprise atleast one member selected from the group consisting of benzyl cocodi-(hydroxyethyl) quaternary amine, p-T-amyl-phenol condensed withformaldehyde, and a copolymer comprising from about 80% to about 100%C1-30 alkylmethacrylate monomers and from about 0% to about 20%hydrophilic monomers. In some embodiments, the aqueous tackifying agentmay comprise a copolymer that comprises from about 90% to about 99.5%2-ethylhexylacrylate and from about 0.5% to about 10% acrylic acid.Suitable hydrophillic monomers may be any monomer that will providepolar oxygen-containing or nitrogen-containing groups. Suitablehydrophillic monomers include dialkyl amino alkyl (meth)acrylates andtheir quaternary addition and acid salts, acrylamide, N-(dialkyl aminoalkyl) acrylamide, methacrylamides and their quaternary addition andacid salts, hydroxy alkyl (meth)acrylates, unsaturated carboxylic acidssuch as methacrylic acid or acrylic acid, hydroxyethyl acrylate,acrylamide, and the like. Combinations of these may be suitable as well.These copolymers can be made by any suitable emulsion polymerizationtechnique. Methods of producing these copolymers are disclosed, forexample, in U.S. Pat. No. 4,670,501, the relevant disclosure of which isincorporated herein by reference.

In some embodiments of the present invention, the consolidating agentmay comprise a resin. The term “resin” as used herein refers to any ofnumerous physically similar polymerized synthetics or chemicallymodified natural resins including thermoplastic materials andthermosetting materials. Resins that may be suitable for use in thepresent invention may include substantially all resins known and used inthe art.

One type of resin suitable for use in the methods of the presentinvention is a two-component epoxy-based resin comprising a liquidhardenable resin component and a liquid hardening agent component. Theliquid hardenable resin component comprises a hardenable resin and anoptional solvent. The solvent may be added to the resin to reduce itsviscosity for ease of handling, mixing and transferring. It is withinthe ability of one skilled in the art, with the benefit of thisdisclosure, to determine if and how much solvent may be needed toachieve a viscosity suitable to the subterranean conditions. Factorsthat may affect this decision include geographic location of the well,the surrounding weather conditions, and the desired long-term stabilityof the consolidating agent. An alternate way to reduce the viscosity ofthe hardenable resin is to heat it. The second component is the liquidhardening agent component, which comprises a hardening agent, anoptional silane coupling agent, a surfactant, an optional hydrolyzableester for, among other things, breaking gelled fracturing fluid films onproppant particulates, and an optional liquid carrier fluid for, amongother things, reducing the viscosity of the hardening agent component.

Examples of hardenable resins that can be used in the liquid hardenableresin component include, but are not limited to, organic resins such asbisphenol A diglycidyl ether resins, butoxymethyl butyl glycidyl etherresins, bisphenol A-epichlorohydrin resins, bisphenol F resins,polyepoxide resins, novolak resins, polyester resins, phenol-aldehyderesins, urea-aldehyde resins, furan resins, urethane resins, glycidylether resins, other epoxide resins, and combinations thereof. In someembodiments, the hardenable resin may comprise a urethane resin.Examples of suitable urethane resins may comprise a polyisocyanatecomponent and a polyhydroxy component. Examples of suitable hardenableresins, including urethane resins, that may be suitable for use in themethods of the present invention include those described in U.S. Pat.Nos. 6,582,819, issued to McDaniel, et al.; U.S. Pat. No. 4,585,064issued to Graham, et al.; U.S. Pat. No. 6,677,426 issued to Noro, etal.; and U.S. Pat. No. 7,153,575 issued to Anderson, et al., therelevant disclosures of which are herein incorporated by reference.

The hardenable resin may be included in the liquid hardenable resincomponent in an amount in the range of about 5% to about 100% by weightof the liquid hardenable resin component. It is within the ability ofone skilled in the art, with the benefit of this disclosure, todetermine how much of the liquid hardenable resin component may beneeded to achieve the desired results. Factors that may affect thisdecision include which type of liquid hardenable resin component andliquid hardening agent component are used.

Any solvent that is compatible with the hardenable resin and achievesthe desired viscosity effect may be suitable for use in the liquidhardenable resin component. Suitable solvents may include butyl lactate,dipropylene glycol methyl ether, dipropylene glycol dimethyl ether,dimethyl formamide, diethyleneglycol methyl ether, ethyleneglycol butylether, diethyleneglycol butyl ether, propylene carbonate, methanol,butyl alcohol, d'limonene, fatty acid methyl esters, and butylglycidylether, and combinations thereof. Other preferred solvents may includeaqueous dissolvable solvents such as, methanol, isopropanol, butanol,and glycol ether solvents, and combinations thereof. Suitable glycolether solvents include, but are not limited to, diethylene glycol methylether, dipropylene glycol methyl ether, 2-butoxy ethanol, ethers of a C₂to C₆ dihydric alkanol containing at least one C₁ to C₆ alkyl group,mono ethers of dihydric alkanols, methoxypropanol, butoxyethanol, andhexoxyethanol, and isomers thereof. Selection of an appropriate solventis dependent on the resin composition chosen and is within the abilityof one skilled in the art, with the benefit of this disclosure.

As described above, use of a solvent in the liquid hardenable resincomponent is optional but may be desirable to reduce the viscosity ofthe hardenable resin component for ease of handling, mixing, andtransferring. However, as previously stated, it may be desirable in someembodiments to not use such a solvent for environmental or safetyreasons. It is within the ability of one skilled in the art, with thebenefit of this disclosure, to determine if and how much solvent isneeded to achieve a suitable viscosity. In some embodiments, the amountof the solvent used in the liquid hardenable resin component may be inthe range of about 0.1% to about 30% by weight of the liquid hardenableresin component. Optionally, the liquid hardenable resin component maybe heated to reduce its viscosity, in place of, or in addition to, usinga solvent.

Examples of the hardening agents that can be used in the liquidhardening agent component include, but are not limited to,cyclo-aliphatic amines, such as piperazine, derivatives of piperazine(e.g., aminoethylpiperazine) and modified piperazines; aromatic amines,such as methylene dianiline, derivatives of methylene dianiline andhydrogenated forms, and 4,4′-diaminodiphenyl sulfone; aliphatic amines,such as ethylene diamine, diethylene triamine, triethylene tetraamine,and tetraethylene pentaamine; imidazole; pyrazole; pyrazine; pyrimidine;pyridazine; 1H-indazole; purine; phthalazine; naphthyridine;quinoxaline; quinazoline; phenazine; imidazolidine; cinnoline;imidazoline; 1,3,5-triazine; thiazole; pteridine; indazole; amines;polyamines; amides; polyamides; and 2-ethyl-4-methyl imidazole; andcombinations thereof. The chosen hardening agent often effects the rangeof temperatures over which a hardenable resin is able to cure. By way ofexample, and not of limitation, in subterranean formations having atemperature of about 60° F. to about 250° F., amines and cyclo-aliphaticamines such as piperidine, triethylamine, tris(dimethylaminomethyl)phenol, and dimethylaminomethyl)phenol may be preferred. In subterraneanformations having higher temperatures, 4,4′-diaminodiphenyl sulfone maybe a suitable hardening agent. Hardening agents that comprise piperazineor a derivative of piperazine have been shown capable of curing varioushardenable resins from temperatures as low as about 50° F. to as high asabout 350° F.

The hardening agent used may be included in the liquid hardening agentcomponent in an amount sufficient to at least partially harden the resincomposition. In some embodiments of the present invention, the hardeningagent used is included in the liquid hardening agent component in therange of about 0.1% to about 95% by weight of the liquid hardening agentcomponent. In other embodiments, the hardening agent used may beincluded in the liquid hardening agent component in an amount of about15% to about 85% by weight of the liquid hardening agent component. Inother embodiments, the hardening agent used may be included in theliquid hardening agent component in an amount of about 15% to about 55%by weight of the liquid hardening agent component.

In some embodiments, the consolidating agent may comprise a liquidhardenable resin component emulsified in a liquid hardening agentcomponent, wherein the liquid hardenable resin component is the internalphase of the emulsion and the liquid hardening agent component is theexternal phase of the emulsion. In other embodiments, the liquidhardenable resin component may be emulsified in water and the liquidhardening agent component may be present in the water. In otherembodiments, the liquid hardenable resin component may be emulsified inwater and the liquid hardening agent component may be providedseparately. Similarly, in other embodiments, both the liquid hardenableresin component and the liquid hardening agent component may both beemulsified in water.

The optional silane coupling agent may be used, among other things, toact as a mediator to help bond the resin to formation particulates orproppant particulates. Examples of suitable silane coupling agentsinclude, but are not limited to,N-2-(aminoethyl)-3-aminopropyltrimethoxysilane, and3-glycidoxypropyltrimethoxysilane, and combinations thereof. The silanecoupling agent may be included in the resin component or the liquidhardening agent component (according to the chemistry of the particulargroup as determined by one skilled in the art with the benefit of thisdisclosure). In some embodiments of the present invention, the silanecoupling agent used is included in the liquid hardening agent componentin the range of about 0.1% to about 3% by weight of the liquid hardeningagent component.

Any surfactant compatible with the hardening agent and capable offacilitating the coating of the resin onto particulates in thesubterranean formation may be used in the liquid hardening agentcomponent. Such surfactants include, but are not limited to, an alkylphosphonate surfactant (e.g., a C₁₂-C₂₂ alkyl phosphonate surfactant),an ethoxylated nonyl phenol phosphate ester, one or more cationicsurfactants, and one or more nonionic surfactants. Mixtures of one ormore cationic and nonionic surfactants also may be suitable. Examples ofsuch surfactant mixtures are described in U.S. Pat. No. 6,311,773 issuedto Todd et al. on Nov. 6, 2001, the relevant disclosure of which isincorporated herein by reference. The surfactant or surfactants that maybe used are included in the liquid hardening agent component in anamount in the range of about 1% to about 10% by weight of the liquidhardening agent component.

While not required, examples of hydrolyzable esters that may be used inthe liquid hardening agent component include, but are not limited to, amixture of dimethylglutarate, dimethyladipate, and dimethylsuccinate;dimethylthiolate; methyl salicylate; dimethyl salicylate; anddimethylsuccinate; and combinations thereof. When used, a hydrolyzableester is included in the liquid hardening agent component in an amountin the range of about 0.1% to about 3% by weight of the liquid hardeningagent component. In some embodiments a hydrolyzable ester is included inthe liquid hardening agent component in an amount in the range of about1% to about 2.5% by weight of the liquid hardening agent component.

Use of a diluent or liquid carrier fluid in the liquid hardening agentcomponent is optional and may be used to reduce the viscosity of theliquid hardening agent component for ease of handling, mixing, andtransferring. As previously stated, it may be desirable in someembodiments to not use such a solvent for environmental or safetyreasons. Any suitable carrier fluid that is compatible with the liquidhardening agent component and achieves the desired viscosity effects issuitable for use in the present invention. Some suitable liquid carrierfluids are those having high flash points (e.g., about 125° F.) becauseof, among other things, environmental and safety concerns; such solventsinclude, but are not limited to, butyl lactate, dipropylene glycolmethyl ether, dipropylene glycol dimethyl ether, dimethyl formamide,diethyleneglycol methyl ether, ethyleneglycol butyl ether,diethyleneglycol butyl ether, propylene carbonate, methanol, butylalcohol, d'limonene, and fatty acid methyl esters, and combinationsthereof. Other suitable liquid carrier fluids include aqueousdissolvable solvents such as, for example, methanol, isopropanol,butanol, glycol ether solvents, and combinations thereof. Suitableglycol ether liquid carrier fluids include, but are not limited to,diethylene glycol methyl ether, dipropylene glycol methyl ether,2-butoxy ethanol, ethers of a C₂ to C₆ dihydric alkanol having at leastone C₁ to C₆ alkyl group, mono ethers of dihydric alkanols,methoxypropanol, butoxyethanol, and hexoxyethanol, and isomers thereof.Combinations of these may be suitable as well. Selection of anappropriate liquid carrier fluid is dependent on, inter alia, the resincomposition chosen.

Other resins suitable for use in the present invention are furan-basedresins. Suitable furan-based resins include, but are not limited to,furfuryl alcohol resins, furfural resins, mixtures furfuryl alcoholresins and aldehydes, and a mixture of furan resins and phenolic resins.Of these, furfuryl alcohol resins may be preferred. A furan-based resinmay be combined with a solvent to control viscosity if desired. Suitablesolvents for use in the furan-based consolidation fluids of the presentinvention include, but are not limited to, 2-butoxy ethanol, butyllactate, butyl acetate, tetrahydrofurfuryl methacrylate,tetrahydrofurfuryl acrylate, esters of oxalic, maleic and succinicacids, and furfuryl acetate. Of these, 2-butoxy ethanol is preferred. Insome embodiments, the furan-based resins suitable for use in the presentinvention may be capable of enduring temperatures well in excess of 350°F. without degrading. In some embodiments, the furan-based resinssuitable for use in the present invention are capable of enduringtemperatures up to about 700° F. without degrading.

Optionally, the furan-based resins suitable for use in the presentinvention may further comprise a curing agent, inter alia, to facilitateor accelerate curing of the furan-based resin at lower temperatures. Thepresence of a curing agent may be particularly useful in embodimentswhere the furan-based resin may be placed within subterranean formationshaving temperatures below about 350° F. Examples of suitable curingagents include, but are not limited to, organic or inorganic acids, suchas, inter alia, maleic acid, fumaric acid, sodium bisulfate,hydrochloric acid, hydrofluoric acid, acetic acid, formic acid,phosphoric acid, sulfonic acid, alkyl benzene sulfonic acids such astoluene sulfonic acid and dodecyl benzene sulfonic acid (“DDBSA”), andcombinations thereof. In those embodiments where a curing agent is notused, the furan-based resin may cure autocatalytically.

Still other resins suitable for use in the methods of the presentinvention are phenolic-based resins. Suitable phenolic-based resinsinclude, but are not limited to, terpolymers of phenol, phenolicformaldehyde resins, and a mixture of phenolic and furan resins. In someembodiments, a mixture of phenolic and furan resins may be preferred. Aphenolic-based resin may be combined with a solvent to control viscosityif desired. Suitable solvents for use in the present invention include,but are not limited to butyl acetate, butyl lactate, furfuryl acetate,and 2-butoxy ethanol. Of these, 2-butoxy ethanol may be preferred insome embodiments.

Yet another resin-type material suitable for use in the methods of thepresent invention is a phenol/phenol formaldehyde/furfuryl alcohol resincomprising of about 5% to about 30% phenol, of about 40% to about 70%phenol formaldehyde, of about 10% to about 40% furfuryl alcohol, ofabout 0.1% to about 3% of a silane coupling agent, and of about 1% toabout 15% of a surfactant. In the phenol/phenol formaldehyde/furfurylalcohol resins suitable for use in the methods of the present invention,suitable silane coupling agents include, but are not limited to,N-2-(aminoethyl)-3-aminopropyltrimethoxysilane, and3-glycidoxypropyltrimethoxysilane. Suitable surfactants include, but arenot limited to, an ethoxylated nonyl phenol phosphate ester, mixtures ofone or more cationic surfactants, and one or more nonionic surfactantsand an alkyl phosphonate surfactant.

In some embodiments, resins suitable for use in the consolidating agentemulsion compositions of the present invention may optionally comprisefiller particles. Suitable filler particles may include any particlethat does not adversely react with the other components used inaccordance with this invention or with the subterranean formation.Examples of suitable filler particles include silica, glass, clay,alumina, fumed silica, carbon black, graphite, mica, meta-silicate,calcium silicate, calcine, kaoline, talc, zirconia, titanium dioxide,fly ash, and boron, and combinations thereof. In some embodiments, thefiller particles may range in size of about 0.01 μm to about 100 μm. Aswill be understood by one skilled in the art, particles of smalleraverage size may be particularly useful in situations where it isdesirable to obtain high proppant pack permeability (i.e.,conductivity), and/or high consolidation strength. In certainembodiments, the filler particles may be included in the resincomposition in an amount of about 0.1% to about 70% by weight of theresin composition. In other embodiments, the filler particles may beincluded in the resin composition in an amount of about 0.5% to about40% by weight of the resin composition. In some embodiments, the fillerparticles may be included in the resin composition in an amount of about1% to about 10% by weight of the resin composition. Some examples ofsuitable resin compositions comprising filler particles are described inU.S. Ser. No. 11/482,601, issued to Rickman, et al., the relevantdisclosure of which is herein incorporated by reference.

Silyl-modified polyamide compounds suitable for use in the consolidatingagent systems of the present invention may be described as substantiallyself-hardening compositions that are capable of at least partiallyadhering to particulates in the unhardened state, and that are furthercapable of self-hardening themselves to a substantially non-tacky stateto which individual particulates such as formation fines will not adhereto, for example, in formation or proppant pack pore throats. Suchsilyl-modified polyamides may be based, for example, on the reactionproduct of a silating compound with a polyamide or a mixture ofpolyamides. The polyamide or mixture of polyamides may be one or morepolyamide intermediate compounds obtained, for example, from thereaction of a polyacid (e.g., diacid or higher) with a polyamine (e.g.,diamine or higher) to form a polyamide polymer with the elimination ofwater. Other suitable silyl-modified polyamides and methods of makingsuch compounds are described in U.S. Pat. No. 6,439,309, issued toMatherly, et al., the relevant disclosure of which is hereinincorporated by reference.

In other embodiments, the consolidating agent systems of the presentinvention comprise crosslinkable aqueous polymer compositions.Generally, suitable crosslinkable aqueous polymer compositions comprisean aqueous solvent, a crosslinkable polymer, and a crosslinking agent.Such compositions are similar to those used to form gelled treatmentfluids, such as fracturing fluids, but according to the methods of thepresent invention, they are not exposed to breakers or de-linkers, andso they retain their viscous nature over time. The aqueous solvent maybe any aqueous solvent in which the crosslinkable composition and thecrosslinking agent may be dissolved, mixed, suspended, or dispersedtherein to facilitate gel formation. For example, the aqueous solventused may be freshwater, salt water, brine, seawater, or any otheraqueous liquid that does not adversely react with the other componentsused in accordance with this invention or with the subterraneanformation.

Examples of crosslinkable polymers that can be used in the crosslinkableaqueous polymer compositions include, but are not limited to,carboxylate-containing polymers and acrylamide-containing polymers. Themost suitable polymers are thought to be those that would absorb oradhere to the rock surfaces so that the rock matrix may be strengthenedwithout occupying a lot of the pore space and/or reducing permeability.Examples of suitable acrylamide-containing polymers includepolyacrylamide, partially hydrolyzed polyacrylamide, copolymers ofacrylamide and acrylate, and carboxylate-containing terpolymers andtetrapolymers of acrylate. Combinations of these may be suitable aswell. Additional examples of suitable crosslinkable polymers includehydratable polymers comprising polysaccharides and derivatives thereof,and that contain one or more of the monosaccharide units, galactose,mannose, glucoside, glucose, xylose, arabinose, fructose, glucuronicacid, or pyranosyl sulfate. Suitable natural hydratable polymersinclude, but are not limited to, guar gum, locust bean gum, tara,konjak, tamarind, starch, cellulose, karaya, xanthan, tragacanth, andcarrageenan, and derivatives of all of the above. Combinations of thesemay be suitable as well. Suitable hydratable synthetic polymers andcopolymers that may be used in the crosslinkable aqueous polymercompositions include, but are not limited to, polycarboxylates such aspolyacrylates and polymethacrylates; polyacrylamides; methylvinyl etherpolymers; polyvinyl alcohols; and polyvinylpyrrolidone. Combinations ofthese may be suitable as well. The crosslinkable polymer used should beincluded in the crosslinkable aqueous polymer composition in an amountsufficient to form the desired gelled substance in the subterraneanformation. In some embodiments of the present invention, thecrosslinkable polymer may be included in the crosslinkable aqueouspolymer composition in an amount in the range of from about 1% to about30% by weight of the aqueous solvent. In another embodiment of thepresent invention, the crosslinkable polymer may be included in thecrosslinkable aqueous polymer composition in an amount in the range offrom about 1% to about 20% by weight of the aqueous solvent.

The crosslinkable aqueous polymer compositions of the present inventionfurther comprise a crosslinking agent for crosslinking the crosslinkablepolymers to form the desired gelled substance. In some embodiments, thecrosslinking agent is a molecule or complex containing a reactivetransition metal cation. A most preferred crosslinking agent comprisestrivalent chromium cations complexed or bonded to anions, atomic oxygen,or water. Examples of suitable crosslinking agents include, but are notlimited to, compounds or complexes containing chromic acetate and/orchromic chloride. Other suitable transition metal cations includechromium VI within a redox system, aluminum III, iron II, iron III, andzirconium IV.

The crosslinking agent should be present in the crosslinkable aqueouspolymer compositions of the present invention in an amount sufficient toprovide, among other things, the desired degree of crosslinking. In someembodiments of the present invention, the crosslinking agent may bepresent in the crosslinkable aqueous polymer compositions of the presentinvention in an amount in the range of from about 0.01% to about 5% byweight of the crosslinkable aqueous polymer composition. The exact typeand amount of crosslinking agent or agents used depends upon thespecific crosslinkable polymer to be crosslinked, formation temperatureconditions, and other factors known to those individuals skilled in theart.

Optionally, the crosslinkable aqueous polymer compositions may furthercomprise a crosslinking delaying agent, such as a polysaccharidecrosslinking delaying agent derived from guar, guar derivatives, orcellulose derivatives. The crosslinking delaying agent may be includedin the crosslinkable aqueous polymer compositions, among other things,to delay crosslinking of the crosslinkable aqueous polymer compositionsuntil desired. One of ordinary skill in the art, with the benefit ofthis disclosure, will know the appropriate amount of the crosslinkingdelaying agent to include in the crosslinkable aqueous polymercompositions for a desired application.

In other embodiments, the consolidating agent systems of the presentinvention comprise polymerizable organic monomer compositions.Generally, suitable polymerizable organic monomer compositions comprisean aqueous-base fluid, a water-soluble polymerizable organic monomer, anoxygen scavenger, and a primary initiator.

The aqueous-based fluid component of the polymerizable organic monomercomposition generally may be freshwater, salt water, brine, seawater, orany other aqueous liquid that does not adversely react with the othercomponents used in accordance with this invention or with thesubterranean formation.

A variety of monomers are suitable for use as the water-solublepolymerizable organic monomers in the present invention. Examples ofsuitable monomers include, but are not limited to, acrylic acid,methacrylic acid, acrylamide, methacrylamide,2-methacrylamido-2-methylpropane sulfonic acid, dimethylacrylamide,vinyl sulfonic acid, N,N-dimethylaminoethylmethacrylate,2-triethylammoniumethylmethacrylate chloride,N,N-dimethyl-aminopropylmethacryl-amide,methacrylamidepropyltriethylammonium chloride, N-vinyl pyrrolidone,vinyl-phosphonic acid, and methacryloyloxyethyl trimethylammoniumsulfate, and combinations thereof. In some embodiments, thewater-soluble polymerizable organic monomer should be self-crosslinking.Examples of suitable monomers which are thought to be self crosslinkinginclude, but are not limited to, hydroxyethylacrylate,hydroxymethylacrylate, hydroxyethylmethacrylate,N-hydroxymethylacrylamide, N-hydroxymethyl-methacrylamide, polyethyleneglycol acrylate, polyethylene glycol methacrylate, polypropylene gylcolacrylate, and polypropylene glycol methacrylate, and combinationsthereof. Of these, hydroxyethylacrylate may be preferred in someinstances. An example of a particularly suitable monomer ishydroxyethylcellulose-vinyl phosphoric acid.

The water-soluble polymerizable organic monomer (or monomers where amixture thereof is used) should be included in the polymerizable organicmonomer composition in an amount sufficient to form the desired gelledsubstance after placement of the polymerizable organic monomercomposition into the subterranean formation. In some embodiments of thepresent invention, the water-soluble polymerizable organic monomer maybe included in the polymerizable organic monomer composition in anamount in the range of from about 1% to about 30% by weight of theaqueous-base fluid. In another embodiment of the present invention, thewater-soluble polymerizable organic monomer may be included in thepolymerizable organic monomer composition in an amount in the range offrom about 1% to about 20% by weight of the aqueous-base fluid.

The presence of oxygen in the polymerizable organic monomer compositionmay inhibit the polymerization process of the water-solublepolymerizable organic monomer or monomers. Therefore, an oxygenscavenger, such as stannous chloride, may be included in thepolymerizable monomer composition. In order to improve the solubility ofstannous chloride so that it may be readily combined with thepolymerizable organic monomer composition on the fly, the stannouschloride may be predissolved in a hydrochloric acid solution. Forexample, the stannous chloride may be dissolved in a 0.1% by weightaqueous hydrochloric acid solution in an amount of about 10% by weightof the resulting solution. The resulting stannous chloride-hydrochloricacid solution may be included in the polymerizable organic monomercomposition in an amount in the range of from about 0.1% to about 10% byweight of the polymerizable organic monomer composition. Generally, thestannous chloride may be included in the polymerizable organic monomercomposition of the present invention in an amount in the range of fromabout 0.005% to about 0.1% by weight of the polymerizable organicmonomer composition.

A primary initiator may be used, among other things, to initiatepolymerization of the water-soluble polymerizable organic monomer(s).Any compound or compounds that form free radicals in aqueous solutionmay be used as the primary initiator. The free radicals act, among otherthings, to initiate polymerization of the water-soluble polymerizableorganic monomer present in the polymerizable organic monomercomposition. Compounds suitable for use as the primary initiatorinclude, but are not limited to, alkali metal persulfates; peroxides;oxidation-reduction systems employing reducing agents, such as sulfitesin combination with oxidizers; and azo polymerization initiators.Suitable azo polymerization initiators include2,2′-azobis(2-imidazole-2-hydroxyethyl) propane,2,2′-azobis(2-aminopropane), 4,4′-azobis(4-cyanovaleric acid), and2,2′-azobis(2-methyl-N-(2-hydroxyethyl)propionamide. Generally, theprimary initiator should be present in the polymerizable organic monomercomposition in an amount sufficient to initiate polymerization of thewater-soluble polymerizable organic monomer(s). In certain embodimentsof the present invention, the primary initiator may be present in thepolymerizable organic monomer composition in an amount in the range offrom about 0.1% to about 5% by weight of the water-soluble polymerizableorganic monomer(s). One skilled in the art, with the benefit of thisdisclosure, will recognize that as the polymerization temperatureincreases, the required level of activator decreases.

Optionally, the polymerizable organic monomer compositions further maycomprise a secondary initiator. A secondary initiator may be used, forexample, where the immature aqueous gel is placed into a subterraneanformation that is relatively cool as compared to the surface mixing,such as when placed below the mud line in offshore operations. Thesecondary initiator may be any suitable water-soluble compound orcompounds that may react with the primary initiator to provide freeradicals at a lower temperature. An example of a suitable secondaryinitiator is triethanolamine. In some embodiments of the presentinvention, the secondary initiator is present in the polymerizableorganic monomer composition in an amount in the range of from about 0.1%to about 5% by weight of the water-soluble polymerizable organicmonomer(s).

Also optionally, the polymerizable organic monomer compositions of thepresent invention may further comprise a crosslinking agent forcrosslinking the polymerizable organic monomer compositions in thedesired gelled substance. In some embodiments, the crosslinking agent isa molecule or complex containing a reactive transition metal cation. Asuitable crosslinking agent comprises trivalent chromium cationscomplexed or bonded to anions, atomic oxygen, or water. Examples ofsuitable crosslinking agents include, but are not limited to, compoundsor complexes containing chromic acetate and/or chromic chloride. Othersuitable transition metal cations include chromium VI within a redoxsystem, aluminum III, iron II, iron III, and zirconium IV. Generally,the crosslinking agent may be present in polymerizable organic monomercompositions in an amount in the range of from 0.01% to about 5% byweight of the polymerizable organic monomer composition.

Other suitable consolidating agent systems are described in U.S. Pat.Nos. 6,196,317, 6,192,986 and 5,836,392, the relevant disclosures ofwhich are incorporated by reference herein.

In other embodiments, the consolidating agent systems of the presentinvention may comprise a consolidating agent emulsion that comprises anaqueous fluid, an emulsifying agent, and a consolidating agent. Theconsolidating agent in suitable emulsions may be either a nonaqueoustackifying agent or a resin, such as those described above. Theseconsolidating agent emulsions have an aqueous external phase andorganic-based internal phase. The term “emulsion” and any derivativesthereof as used herein refers to a mixture of two or more immisciblephases and includes, but is not limited to, dispersions and suspensions.

Suitable consolidating agent emulsions comprise an aqueous externalphase comprising an aqueous fluid. Suitable aqueous fluids that may beused in the consolidating agent emulsions of the present inventioninclude freshwater, salt water, brine, seawater, or any other aqueousfluid that, preferably, does not adversely react with the othercomponents used in accordance with this invention or with thesubterranean formation. One should note, however, that if long-termstability of the emulsion is desired, a more suitable aqueous fluid maybe one that is substantially free of salts. It is within the ability ofone skilled in the art, with the benefit of this disclosure, todetermine if and how much salt may be tolerated in the consolidatingagent emulsions of the present invention before it becomes problematicfor the stability of the emulsion. The aqueous fluid may be present inthe consolidating agent emulsions in an amount in the range of about 20%to 99.9% by weight of the consolidating agent emulsion composition. Insome embodiments, the aqueous fluid may be present in the consolidatingagent emulsions in an amount in the range of about 60% to 99.9% byweight of the consolidating agent emulsion composition. In someembodiments, the aqueous fluid may be present in the consolidating agentemulsions in an amount in the range of about 95% to 99.9% by weight ofthe consolidating agent emulsion composition.

The consolidating agent in the emulsion may be either a nonaqueoustackifying agent or a resin, such as those described above. Theconsolidating agents may be present in a consolidating agent emulsion inan amount in the range of about 0.1% to about 80% by weight of theconsolidating agent emulsion composition. In some embodiments, theconsolidating agent may be present in a consolidating agent emulsion inan amount in the range of about 0.1% to about 40% by weight of thecomposition. In some embodiments, the consolidating agent may be presentin a consolidating agent emulsion in an amount in the range of about0.1% to about 5% by weight of the composition.

As previously stated, the consolidating agent emulsions comprise anemulsifying agent. Examples of suitable emulsifying agents may includesurfactants, proteins, hydrolyzed proteins, lipids, glycolipids, andnanosized particulates, including, but not limited to, fumed silica.Combinations of these may be suitable as well.

Surfactants that may be used in suitable consolidating agent emulsionsare those capable of emulsifying an organic-based component in anaqueous-based component so that the emulsion has an aqueous externalphase and an organic internal phase. In some embodiments, the surfactantmay comprise an amine surfactant. Such suitable amine surfactantsinclude, but are not limited to, amine ethoxylates and amine ethoxylatedquaternary salts such as tallow diamine and tallow triamine exthoxylatesand quaternary salts. Examples of suitable surfactants are ethoxylatedC₁₂-C₂₂ diamine, ethoxylated C₁₂-C₂₂ triamine, ethoxylated C₁₂-C₂₂tetraamine, ethoxylated C₁₂-C₂₂ diamine methylchloride quat, ethoxylatedC₁₂-C₂₂ triamine methylchloride quat, ethoxylated C₁₂-C₂₂ tetraaminemethylchloride quat, ethoxylated C₁₂-C₂₂ diamine reacted with sodiumchloroacetate, ethoxylated C₁₂-C₂₂ triamine reacted with sodiumchloroacetate, ethoxylated C₁₂-C₂₂ tetraamine reacted with sodiumchloroacetate, ethoxylated C₁₂-C₂₂ diamine acetate salt, ethoxylatedC₁₂-C₂₂ diamine hydrochloric acid salt, ethoxylated C₁₂-C₂₂ diamineglycolic acid salt, ethoxylated C₁₂-C₂₂ diamine DDBSA salt, ethoxylatedC₁₂-C₂₂ triamine acetate salt, ethoxylated C₁₂-C₂₂ triamine hydrochloricacid salt, ethoxylated C₁₂-C₂₂ triamine glycolic acid salt, ethoxylatedC₁₂-C₂₂ triamine DDBSA salt, ethoxylated C₁₂-C₂₂ tetraamine acetatesalt, ethoxylated C₁₂-C₂₂ tetraamine hydrochloric acid salt, ethoxylatedC₁₂-C₂₂ tetraamine glycolic acid salt, ethoxylated C₁₂-C₂₂ tetraamineDDBSA salt, pentamethylated C₁₂-C₂₂ diamine quat, heptamethylatedC₁₂-C₂₂ diamine quat, nonamethylated C₁₂-C₂₂ diamine quat, andcombinations thereof.

In some embodiments, a suitable amine surfactant may have the generalformula:

(CH₂CHR′A)_(x)H

R—N

(CH₂CHR′A)_(y)H

wherein R is a C₁₂-C₂₂ aliphatic hydrocarbon; R′ is independentlyselected from hydrogen or C₁ to C₃ alkyl group; A is independentlyselected from NH or O, and x+y has a value greater than or equal to onebut also less than or equal to three. Preferably, the R group is anon-cyclic aliphatic. In some embodiments, the R group contains at leastone degree of unsaturation, i.e., at least one carbon-carbon doublebond. In other embodiments, the R group may be a commercially recognizedmixture of aliphatic hydrocarbons such as soya, which is a mixture ofC₁₄ to C₂₀ hydrocarbons; or tallow, which is a mixture of C₁₆ to C₂₀aliphatic hydrocarbons; or tall oil, which is a mixture of C₁₄ to C₁₈aliphatic hydrocarbons. In other embodiments, one in which the A groupis NH, the value of x+y is preferably two, with x having a preferredvalue of one. In other embodiments, in which the A group is O, thepreferred value of x+y is two, with the value of x being preferably one.Commercially available surfactant examples include ETHOMEEN T/12, adiethoxylated tallow amine; ETHOMEEN S/12, a diethoxylated soya amine;DUOMEEN O, a N-oleyl-1,3-diaminopropane; DUOMEEN T, aN-tallow-1,3-diaminopropane; all of which are commercially availablefrom Akzo Nobel at various locations.

In other embodiments, the surfactant may be a tertiary alkyl amineethoxylate. TRITON RW-100 surfactant and TRITON RW-150 surfactant areexamples of tertiary alkyl amine ethoxylates that are commerciallyavailable from Dow Chemical Company.

In other embodiments, the surfactant may be a combination of anamphoteric surfactant and an anionic surfactant. In some embodiments,the relative amounts of the amphoteric surfactant and the anionicsurfactant in the surfactant mixture may be of about 30% to about 45% byweight of the surfactant mixture and of about 55% to about 70% by weightof the surfactant mixture, respectively. The amphoteric surfactant maybe lauryl amine oxide, a mixture of lauryl amine oxide and myristylamine oxide (i.e., a lauryl/myristyl amine oxide), cocoamine oxide,lauryl betaine, and oleyl betaine, or combinations thereof, with thelauryl/myristyl amine oxide being preferred. The cationic surfactant maybe cocoalkyltriethyl ammonium chloride, and hexadecyltrimethyl ammoniumchloride, or combinations thereof, with a 50/50 mixture by weight of thecocoalkyltriethyl ammonium chloride and the hexadecyltrimethyl ammoniumchloride being preferred.

In other embodiments, the surfactant may be a nonionic surfactant.Examples of suitable nonionic surfactants include, but are not limitedto, alcohol oxylalkylates, alkyl phenol oxylalkylates, nonionic esters,such as sorbitan esters, and alkoxylates of sorbitan esters. Examples ofsuitable surfactants include, but are not limited to, castor oilalkoxylates, fatty acid alkoxylates, lauryl alcohol alkoxylates,nonylphenol alkoxylates, octylphenol alkoxylates, tridecyl alcoholalkoxylates, such as polyoxyethylene (“POE”)-10 nonylphenol ethoxylate,POE-100 nonylphenol ethoxylate, POE-12 nonylphenol ethoxylate, POE-12octylphenol ethoxylate, POE-12 tridecyl alcohol ethoxylate, POE-14nonylphenol ethoxylate, POE-15 nonylphenol ethoxylate, POE-18 tridecylalcohol ethoxylate, POE-20 nonylphenol ethoxylate, POE-20 oleyl alcoholethoxylate, POE-20 stearic acid ethoxylate, POE-3 tridecyl alcoholethoxylate, POE-30 nonylphenol ethoxylate, POE-30 octylphenolethoxylate, POE-34 nonylphenol ethoxylate, POE-4 nonylphenol ethoxylate,POE-40 castor oil ethoxylate, POE-40 nonylphenol ethoxylate, POE-40octylphenol ethoxylate, POE-50 nonylphenol ethoxylate, POE-50 tridecylalcohol ethoxylate, POE-6 nonylphenol ethoxylate, POE-6 tridecyl alcoholethoxylate, POE-8 nonylphenol ethoxylate, POE-9 octylphenol ethoxylate,mannide monooleate, sorbitan isostearate, sorbitan laurate, sorbitanmonoisostearate, sorbitan monolaurate, sorbitan monooleate, sorbitanmonopalmitate, sorbitan monostearate, sorbitan oleate, sorbitanpalmitate, sorbitan sesquioleate, sorbitan stearate, sorbitan trioleate,sorbitan tristearate, POE-20 sorbitan monoisostearate ethoxylate, POE-20sorbitan monolaurate ethoxylate, POE-20 sorbitan monooleate ethoxylate,POE-20 sorbitan monopalmitate ethoxylate, POE-20 sorbitan monostearateethoxylate, POE-20 sorbitan trioleate ethoxylate, POE-20 sorbitantristearate ethoxylate, POE-30 sorbitan tetraoleate ethoxylate, POE-40sorbitan tetraoleate ethoxylate, POE-6 sorbitan hexastearate ethoxylate,POE-6 sorbitan monstearate ethoxylate, POE-6 sorbitan tetraoleateethoxylate, and/or POE-60 sorbitan tetrastearate ethoxylate. Somesuitable nonionic surfactants include alcohol oxyalkyalates such asPOE-23 lauryl alcohol, and alkyl phenol ethoxylates such as POE (20)nonyl phenyl ether.

While cationic, amphoteric, and nonionic surfactants are thought to bemost suitable, any suitable emulsifying surfactant may be used. Goodsurfactants for emulsification typically need to be either ionic, togive charge stabilization, to have a sufficient hydrocarbon chain lengthor cause a tighter packing of the hydrophobic groups at the oil/waterinterface to increase the stability of the emulsion. One of ordinaryskill in the art, with the benefit of this disclosure, will be able toselect a suitable surfactant depending upon the consolidating agent thatis being emulsified. Additional suitable surfactants may include othercationic surfactants and even anionic surfactants. Examples include, butare not limited to, hexahydro-1 3,5-tris (2-hydroxyethyl) triazine,alkyl ether phosphate, ammonium lauryl sulfate, ammonium nonylphenolethoxylate sulfate, branched isopropyl amine dodecylbenzene sulfonate,branched sodium dodecylbenzene sulfonate, dodecylbenzene sulfonic acid,branched dodecylbenzene sulfonic acid, fatty acid sulfonate potassiumsalt, phosphate esters, POE-1 ammonium lauryl ether sulfate, OE-1 sodiumlauryl ether sulfate, POE-10 nonylphenol ethoxylate phosphate ester,POE-12 ammonium lauryl ether sulfate, POE-12 linear phosphate ester,POE-12 sodium lauryl ether sulfate, POE-12 tridecyl alcohol phosphateester, POE-2 ammonium lauryl ether sulfate, POE-2 sodium lauryl ethersulfate, POE-3 ammonium lauryl ether sulfate, POE-3 disodium alkyl ethersulfosuccinate, POE-3 linear phosphate ester, POE-3 sodium lauryl ethersulfate, POE-3 sodium octylphenol ethoxylate sulfate, POE-3 sodiumtridecyl ether sulfate, POE-3 tridecyl alcohol phosphate ester, POE-30ammonium lauryl ether sulfate, POE-30 sodium lauryl ether sulfate, POE-4ammonium lauryl ether sulfate, POE-4 ammonium nonylphenol ethoxylatesulfate, POE-4 nonyl phenol ether sulfate, POE-4 nonylphenol ethoxylatephosphate ester, POE-4 sodium lauryl ether sulfate, POE-4 sodiumnonylphenol ethoxylate sulfate, POE-4 sodium tridecyl ether sulfate,POE-50 sodium lauryl ether sulfate, POE-6 disodium alkyl ethersulfosuccinate, POE-6 nonylphenol ethoxylate phosphate ester, POE-6tridecyl alcohol phosphate ester, POE-7 linear phosphate ester, POE-8nonylphenol ethoxylate phosphate ester, potassium dodecylbenzenesulfonate, sodium 2-ethyl hexyl sulfate, sodium alkyl ether sulfate,sodium alkyl sulfate, sodium alpha olefin sulfonate, sodium decylsulfate, sodium dodecylbenzene sulfonate, sodium lauryl sulfate, sodiumlauryl sulfoacetate, sodium nonylphenol ethoxylate sulfate, and/orsodium octyl sulfate.

Other suitable emulsifying agents are described in U.S. Pat. Nos.6,653,436 and 6,956,086, both issued to Back, et al., the relevantdisclosures of which are herein incorporated by reference.

In some embodiments, the emulsifying agent may function in more than onecapacity. For example, in some embodiments, a suitable emulsifying agentmay also be a hardening agent. Examples of suitable emulsifying agentsthat may also function as a hardening agent include, but are not limitedto, those described in U.S. Pat. No. 5,874,490, the relevant disclosureof which is herein incorporated by reference.

In some embodiments, the emulsifying agent may be present in theconsolidating agent emulsion in an amount in the range of about 0.001%to about 10% by weight of the consolidating agent emulsion composition.In some embodiments, the emulsifying agent may be present in theconsolidating agent emulsion in an amount in the range of about 0.05% toabout 5% by weight of the consolidating agent emulsion composition.

Optionally, a consolidating agent emulsion may comprise additionaladditives such as emulsion stabilizers, emulsion destabilizers,antifreeze agents, biocides, algaecides, pH control additives, oxygenscavengers, clay stabilizers, and the like, or any other additive thatdoes not adversely affect the consolidating agent emulsion compositions.For instance, an emulsion stabilizer may be beneficial when stability ofthe emulsion is desired for a lengthened period of time or at specifiedtemperatures. The emulsion stabilizer may be any acid. In someembodiments, the emulsion stabilizer may be an organic acid, such asacetic acid. In some embodiments, the emulsion stabilizer may be aplurality of nanoparticulates. If an emulsion stabilizer is utilized, itis preferably present in an amount necessary to stabilize theconsolidating agent emulsion composition. An emulsion destabilizer maybe beneficial when stability of the emulsion is not desired. Theemulsion destabilizer may be, inter alia, an alcohol, a pH additive, asurfactant, or an oil. If an emulsion destabilizer is utilized, it ispreferably present in an amount necessary to break the emulsion.Additionally, antifreeze agents may be beneficial to improve thefreezing point of the emulsion. In some embodiments, optional additivesmay be included in the consolidating agent emulsion in an amount in therange of about 0.001% to about 10% by weight of the consolidating agentemulsion composition. One of ordinary skill in the art, with the benefitof this disclosure, will recognize that the compatibility of any givenadditive should be tested to ensure that it does not adversely affectthe performance of the consolidating agent emulsion.

In some embodiments, a consolidating agent emulsion may further comprisea foaming agent. As used herein, the term “foamed” also refers toco-mingled fluids. In certain embodiments, it may desirable that theconsolidating agent emulsion is foamed to, inter alia, provide enhancedplacement of a consolidating agent emulsion composition and/or to reducethe amount of aqueous fluid that may be required, e.g., inwater-sensitive subterranean formations. Various gases can be utilizedfor foaming the consolidating agent emulsions of this invention,including, but not limited to, nitrogen, carbon dioxide, air, andmethane, and mixtures thereof. One of ordinary skill in the art, withthe benefit of this disclosure, will be able to select an appropriategas that may be utilized for foaming the consolidating agent emulsionsof the present invention. In some embodiments, the gas may be present ina consolidating agent emulsion of the present invention in an amount inthe range of about 5% to about 98% by volume of the consolidating agentemulsion. In some embodiments, the gas may be present in a consolidatingagent emulsion of the present invention in an amount in the range ofabout 20% to about 80% by volume of the consolidating agent emulsion. Insome embodiments, the gas may be present in a consolidating agentemulsion of the present invention in an amount in the range of about 30%to about 70% by volume of the consolidating agent emulsion. The amountof gas to incorporate into the consolidating agent emulsion may beaffected by factors, including the viscosity of the consolidating agentemulsion and wellhead pressures involved in a particular application.

In those embodiments where it is desirable to foam the consolidatingagent emulsion, surfactants such as HY-CLEAN (HC-2)™ surface-activesuspending agent, PEN-5™, or AQF-2™ additive, all of which arecommercially available from Halliburton Energy Services, Inc., ofDuncan, Okla., may be used. Additional examples of foaming agents thatmay be utilized to foam and stabilize the consolidating agent emulsionsmay include, but are not limited to, betaines, amine oxides, methylester sulfonates, alkylamidobetaines such as cocoamidopropyl betaine,alpha-olefin sulfonate, trimethyltallowammonium chloride, C₈ to C₂₂alkylethoxylate sulfate and trimethylcocoammonium chloride. Othersuitable foaming agents and foam-stabilizing agents may be included aswell, which will be known to those skilled in the art with the benefitof this disclosure.

FIG. 1 f illustrates consolidating agent system 106 in place aftersufficient time has passed. Depending on the specific job, placing thewell in service may include producing, with completion tubing 130 beingproduction tubing, as illustrated by FIG. 1 g. Alternatively, placingthe well in service may include injecting, with completion tubing 130being injection tubing, as illustrated by FIG. 1 h.

While the embodiment of FIGS. 1 a-1 h shows filter cake degradationfluid 118 acting during the removal of service assembly 124, theembodiment of FIGS. 2 a-2 g illustrates an alternative method.

In this embodiment, service assembly 124 may remain in place until afterconsolidating agent system 106 has been pumped into the formation. Thisallows borehole support assembly 102 to include a slotted liner, wherewash pipe 110 may be removed. In this embodiment, borehole supportassembly 102 may alternatively be a cemented casing with perforations.Thus, flow distributor 104 may be installed into a long perforatedinterval with cup packers 134 to distribute flow over the long interval.As illustrated in FIG. 2 a, cup packers 134 may be used to selectivelyplace flow. Filter cake degradation fluid 118 may be pumped through washpipe 110, which includes flow distributor 104. After passing throughflow distributor 104, filter cake degradation fluid 118 may pass throughborehole support assembly 102 before coming into contact with filtercake 112.

After filter cake degradation fluid 118 is pumped, in embodiments wheresuch a fluid is desirable, sufficient time must pass to allow filtercake 112 to be compromised and/or to allow annular barriers 120 toactivate. As illustrated in FIG. 2 c, consolidating agent system 106 maybe pumped after filter cake 112 is compromised and annular barriers 120are activated. After consolidating agent system 106 is placed, asillustrated in FIG. 2 d, service assembly 124 may be removed andcompletion tubing 130 may be placed as illustrated in FIG. 2 e. Aftercompletion tubing 130 is placed, the well may be placed in service.Depending on the specific job, placing the well in service may includeproducing, with completion tubing 130 being production tubing, asillustrated by FIG. 2 f. Alternatively, placing the well in service mayinclude injecting, with completion tubing 130 being injection tubing, asillustrated by FIG. 2 g.

Yet further alternative methods involve self-degrading filter cakes thatdo not require filter cake degradation fluid 118. Referring to FIG. 3 a,flow distribution system 100, including wash pipe 110 and boreholesupport assembly 102, may be supported by suspension tool 122.Self-diverting fluid 132 flows into the space between wash pipe 110 andborehole support assembly 102, and out through borehole support assembly102 as illustrated in FIG. 3 b. Self-diverting fluid 132 may be placedafter flow distribution system 100, and essentially divert subsequentflow away from high permeability sections, allowing a more uniform flowto be obtained, which may allow for effective treatment of the entirewell bore.

In some instances, it may be desirable to take partial returns 136 ofconsolidating agent system 28. Taking at least partial returns 136 helpsensure exposure to the entire borehole. Self-diverting fluid 132 mayequalize flow into reservoir 108, allowing flow distributors 104 to beomitted. For example, at least about 5% returns may help ensure fullzone coverage. FIG. 3 c illustrates the passage of sufficient time tocompromise filter cake 112. FIG. 3 d illustrates consolidating agentsystem 106 as it is placed. FIG. 3 e illustrates consolidating agentsystem 106 in place. Service assembly 124 may be pulled out of the hole,leaving fluid loss valve 126 closed to prevent losses. Circulation mayremove excess treating fluids from the well and completion tubing 130may be run, as illustrated in FIG. 3 f. With completion tubing 130 inplace, the well may be placed in service. Depending on the specific job,placing the well in service may include producing, with completiontubing 130 being production tubing, as illustrated by FIG. 3g.Alternatively, placing the well in service may include injecting, withcompletion tubing 130 being injection tubing, as illustrated by FIG. 3h. In one embodiment, annular barriers 120 may be added, such that theymay be activated after consolidating agent system 106 has been placed.

In yet another embodiment, flow distributors 104 may be used to placeself-diverting fluid 132 over the desired interval. The diversionproperties of self-diverting fluid may allow for uniform treatment overa long interval. In this embodiment, annular compartmentalization is notrequired unless, in some instances for example, it might be desirable toisolate shale that cannot be treated. Therefore, as with the embodimentof FIGS. 3 a-3 h, annular barriers 120 may optionally be omitted. Filtercake 112 may be removed using filter cake degradation fluid 118,allowing time for filter cake 112 to degrade. Filter cake degradationfluid 118 may also be used to activate annular barriers 120 for shaleisolation if desired. Consolidating agent system 106 may be placed usingself-diverting fluid 132. Consolidating agent system 106 may then besqueezed using flow distribution system 100 to distribute over theentire interval. Service assembly 124, including wash pipe 110, may bepulled out, leaving fluid loss valve 126 closed to prevent losses.Completion tubing 130 may be installed, and the well may be placed inservice. If annular barriers 120 are used and were not activatedpre-treatment, they may be activated during production of the well toisolate any exposed shale.

Consolidating agent system 106 may be placed along entire well bore 114,or any portion thereof. A majority of the interval may be treated insome instances. A majority means at least about 50% of a choseninterval. Note that not all steps are always required; for instance, onemight choose not to isolate the shale or when consolidating agent system106 is placed during drilling, there is no need to remove filter cake112.

Therefore, the present invention is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent invention may be modified and practiced in different butequivalent manners apparent to those skilled in the art, having thebenefit of the teachings herein. Furthermore, no limitations areintended to the details of construction or design herein shown, otherthan as described in the claims below. It is therefore evident that theparticular illustrative embodiments disclosed above may be altered ormodified, and all such variations are considered within the scope andspirit of the present invention. In particular, every range of values(of the form, “from about a to about b,” or, equivalently, “fromapproximately a to b,” or, equivalently, “from approximately a-b”)disclosed herein is to be understood as referring to the power set (theset of all subsets) of the respective range of values, and set forthevery range encompassed within the broader range of values. Moreover,the indefinite articles “a” or “an”, as used in the claims and thedescription, are defined herein to mean one or more than one of theelement that it introduces. Also, the terms in the claims have theirplain, ordinary meaning unless otherwise explicitly and clearly definedby the patentee.

1. A method comprising: providing a well bore comprising an open holesection of about 30 feet or more that comprises a filter cakeneighboring at least a portion of a reservoir in a subterraneanformation; placing a flow distribution system in the open hole section,the flow distribution system comprising a plurality of annular barriers;compromising the integrity of the filter cake; activating at least oneof the annular barriers; and placing a consolidating agent system intothe formation to at least partially reduce particulate migration in theopen hole section.
 2. The method of claim 1, wherein the filter cake isat least partially self-degrading due to the presence of at least oneself-degrading bridging agent that comprises a degradable materialchosen from the group consisting of: an ortho ester; a poly(orthoester);an aliphatic polyester; a lactide; a poly(lactide); a glycolide; apoly(glycolide); a poly(α-caprolactone); a poly(hydroxybutyrate); asubstantially water-insoluble anhydride; a poly(anhydride); and apoly(amino acid).
 3. The method of claim 1, wherein the open holesection is about 50 feet or more.
 4. The method of claim 1, wherein theopen hole section is about 100 feet or more.
 5. The method of claim 1,wherein the step of allowing the integrity of the filter cake to becomecompromised involves placing a filter cake degradation fluid in contactwith at least a portion of the filter cake.
 6. The method of claim 5,wherein the filter cake degradation fluid comprises at least one chosenfrom the group consisting of: an aqueous fluid; an acid; an acidprecursor; an oxidizer; an oxidizer precursor; a base; an enzyme; and anoil-soluble acid; an oil-based fluid; and any combination thereof. 7.The method of claim 5, wherein the filter cake degradation fluid isinvolved in activating the annular barriers.
 8. The method of claim 1,further comprising placing the well in service, which involves producingfrom the well and/or injecting into the well.
 9. The method of claim 1,wherein at least one of the annular barriers comprises an annularisolation device.
 10. The method of claim 9, wherein the annularisolation device responds to a fluid present within the subterraneanformation to substantially isolate at least a portion of the open holesection.
 11. The method of claim 1, wherein the consolidating agentsystem comprises a pre-flush fluid and/or a post-flush fluid.
 12. Themethod of claim 1, wherein the consolidating agent system comprises aconsolidating agent chosen from the group consisting of: a resin; atackifier; a silyl-modified polyamide compound; a crosslinkable aqueouspolymer composition; a polymerizable organic monomer composition; and aconsolidating agent emulsion; and any combination thereof.
 13. A methodcomprising: providing a well bore comprising an open hole section ofabout 30 feet or more that comprises a filter cake neighboring at leasta portion of a reservoir; allowing the integrity of at least a portionof the filter cake to become compromised; and treating at least aportion of the open hole section with a consolidating agent system in asingle stage operation so as to at least partially reduce particulatemigration in the open hole section.
 14. The method of claim 13, whereinthe consolidating agent system comprises a consolidating agent chosenfrom the group consisting of: a resin; a tackifier; a silyl-modifiedpolyamide compound; a crosslinkable aqueous polymer composition; apolymerizable organic monomer composition; a consolidating agentemulsion that comprises an aqueous fluid, an emulsifying agent, and aconsolidating agent; and any combination thereof.
 15. The method ofclaim 13, wherein the filter cake is at least partially self-degrading.16. The method of claim 13, wherein the step of allowing the integrityof the filter cake to become compromised involves placing a filter cakedegradation fluid in contact with at least a portion of the filter cake.17. A method comprising: providing a well bore comprising an open holesection of about 30 feet or more that comprises a filter cakeneighboring a reservoir; allowing the integrity of the filter cake tobecome compromised; and placing a consolidating agent system into theformation in a single stage operation so as to at least partially reduceparticulate migration in a portion of the open hole section.
 18. Themethod of claim 17, further comprising placing the well in service. 19.The method of claim 17, wherein the consolidating agent system comprisesa consolidating agent chosen from the group consisting of: a resin; atackifier; a silyl-modified polyamide compound; a crosslinkable aqueouspolymer composition; a polymerizable organic monomer composition; and aconsolidating agent emulsion; and any combination thereof.
 20. Themethod of claim 17, wherein the filter cake is at least partiallyself-degrading.
 21. The method of claim 17, wherein the long interval isabout 100 feet or more.
 22. The method of claim 17, wherein the step ofallowing the integrity of the filter cake to become compromised involvesplacing a filter cake degradation fluid in contact with at least aportion of the filter cake.
 23. The method of claim 17 furthercomprising placing a flow distribution system in the open hole section,the flow distribution system comprising a plurality of annular barriers,and activating the annular barriers before the integrity of the filtercake becomes substantially compromised.